Natural gas supplies in storage fell under one trillion cubic feet for the first time since 2003.
Oil rigs rose +12 to 1,473 and the most ever since Baker Hughes began separating gas and oil rigs in the count in 1987. Active gas rigs declined by -18 to 326 and nearly a 20 year low. This is strange since gas prices are at multiyear highs. However, rig planning occurs months in advance and is dictated in part by having to drill wells to hold leases. The continued growth of active oil rigs means more production six months from now.
Sterne Agee analyst Stephen Gengaro said the extreme weather in January and February cut down significantly on the number of wells drilled and completed in the Bakken. He said the number of completions fell from 119 in December to only 60 in January. He said at the end of January there were 660 wells waiting to be completed. He lowered earnings estimates for Halliburton, Baker Hughes and Schlumberger due to the slower pace of fracking and completions early in the quarter.
Natural gas supplies in the U.S. fell to a 10 year low last week with a decline of -48 Bcf to 953 Bcf in storage. The average for this time of year is 1,830 Bcf. This was the first time supplies in inventory fell below one trillion cubic feet (Tcf) since 2003. Inventories today are -932 Bcf below year ago levels.
While winter weather is waning there are still forecasts for colder than normal weather over the next two weeks. The Northeast is getting snow again this weekend along with the Midwest. If storage levels end March about where they are now it will be a race to rebuild supplies before next winter.
It will be necessary to add nearly 3,000 Bcf to storage (3.0 Tcf) before November. That means we will need to add about 14 Bcf per day to storage for the entire spring and summer. That is about 4.5 Bcf per day higher than normal. The U.S. produced 71.16 Bcf per day in December. In 2013 we consumed an average of 71.33 Bcf per day. Gas demand varies greatly depending on the season. For instance in December we consumed 93.92 Bcf per day. Obviously those quick at math see the problem.
To make up for that 22 Bcf per day of excess demand in the winter months we have to produce gas and put it in storage in the summer months. We simply don't produce enough gas on a daily basis to fill the winter demand. This year demand was very strong and that means we will need to replenish that gas before next winter. With active rigs drilling for gas falling to 326 and the lowest number since May 1995 the outlook for gas production is not good. With new wells drilled over the last three years rapidly depleting it will be difficult to increase production to the point where we can put the normal 9 Bcf per day in storage much less the 14 Bcf per day that it will take to return storage levels to normal before November.
It is not a question of whether or not we have the gas. We have plenty of gas currently undrilled. The price of gas is the problem. While gas is now in the range of $4.30 per Mcf that spike in prices occurred over just the last several months. In November it was as low as $3.37. The high gas prices will probably encourage some producers to drill more but the push now is to drill for oil with prices holding in the high $90 range and expected to rise.
Exploration and production companies were burned over the last decade after they invested so much effort into buying gas leases and contracting rigs to drill only to have gas prices implode and drilling became unprofitable. It may be a challenge to get them to go back to the gas fields.
We will see some lower demand for gas this summer if prices stay high. Utility companies are going back to coal with $3.00 gas the breakeven point. As long as gas remains over that level it is cheaper to burn coal. However, that is estimated to be only about 2.0 Bcf of reduced demand. That is hardly enough to help out on the inventory problem. Rising industrial use is expected to increase demand by about 1.5-2.0 Bcf/pd so no additional gas availability there.
In a couple years when the various LNG export terminals begin operation the situation will become even worse. Initially they will take 2.5-4.0 bcf per day out of the system. Once all the plants that have been approved begin operation it will remove about 10 Bcf/pd from the system. That will be in the 2018-2019 range.
If you have been paying attention you know we are already short on gas to put back into storage. We can probably do about 7-9 Bcf per day in the spring when demand is low but we need 14 bcf.
The bottom line to this analysis is that gas prices are probably going to decline for the next several weeks but long term they are going higher. As normal demand increases and storage is not being replenished fast enough prices will rise. This will eventually bring producers back into the gas fields but this is a long term scenario. There is plenty of gas in the Marcellus if the infrastructure was there to move it from the fields to the major pipelines. That is being built every day but that is also a long term project.
After this spring I think the long term price of gas is going back to $5 or more. It is a function of supply and demand and right now supply and demand are almost dead even at 71 Bcf/pd with a high percentage of recently drilled wells depleting at a high rate. If we don't add another 5-7 Bcf per day in production over the next two years the prices are going a lot higher. The age of cheap gas is about over. With a 10 year low of gas in storage and a 19 year low in active gas rigs something has to change soon.
Gulf of Mexico Leases
The U.S. collected $872 million in the latest round of lease sales in the Gulf of Mexico. Over 1.7 million acres in 329 tracts of potential oil and gas reserves were offered. They received a total of 380 bids from 50 companies.
BP submitted 24 winning bids only a week after the company received permission to return to the Gulf after the Deepwater Horizon/Macondo disaster. The EPA lifted the ban that was enforced in 2012 and allowed BP to bid on the leases. BP won 24 of the 31 bids it placed for a total of $41.6 million. Some of the leases it bid on were near the Macondo disaster site.
Most of the bids were won by smaller oil companies. The oil giants like BP and Exxon were barely evident in the bidding process. Exxon bid on only three tracts for $55.4 million and only won one of them at $4.6 million. In the last auction they spent $220.3 million. Shell only bid $100 million in this auction compared to $166.3 million in the prior auction. BHP Billiton bid $198.5 million in the prior auction and only spent $2.4 million this year.
Energy XXI said it was the high bidder on 10 shallow-water blocks in the Central Gulf Lease Sale 231. The total of the winning bids was $2.6 million. Eight blocks were solely won by EXXI and two blocks were bid with partners Fieldwood and Apache. Blocks bid were adjacent to existing EXXI production and could provide near-term development opportunities.
EPL Energy, which is being acquired by EXXI, was the high bidder on 21 leases totaling 92,030 acres on the shallow water shelf. EPL's total bids were $8.2 million. Most of these leases are adjacent to EXXI production and EPL production so this was again another bargain for EXXI.
Freeport McMoran (FCX) was the high bidder on 20 tracts in the Gulf lease sale with successful bids totaling $330 million. The blocks were in the Mississippi Canyon and Atwater Valley areas to complement existing FCX production facilities and increase exploration potential. The blocks cover about 106,000 acres in water depths up to 6,000 feet. FCX through its oil and gas segment, recently renamed FM O&G, expects to be named the operator on these leases. FM won 16 of the 17 bids it placed. The $330 million was three times the $104 million Chevron spent on winning bids.
The larger companies like Exxon, Conoco, Chevron, Shell, etc are all cutting back on lease spending because they have so much existing acreage they can't develop it all. These monster discoveries take 5-7 or even 10 years to develop and hundreds of millions, sometimes billions of dollars. All their money is going into wells rather than new leases.
The market posted gains last week but they were blunted by a disappointing performance on Friday. Option expiration, S&P rebalancing and bearish comments from several Fed speakers all added to the selling process.
The last week of March is seasonally negative about 71% of the time. There are various factors at play including the end of the quarter portfolio rebalancing. I believe the market will go higher in April but next week is a coin toss.
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