How Do We Burn U.S. Natural Gas Surplus:

How Do We Burn U.S. Natural Gas Surplus:

Global Arbitrage? Jan 18,2012

Charring cinders of nat gas pricing.

Due to warmer than expected weather and growing natural gas surpluses caused by ever increasing production, spot prices for natural gas have been taking a hit. This naturally impinges on the margins of North American producers….one would think.  But production pops and M&A  speculation continues.  Hope continues to ignite with reports of incredible finds in shale from North Dakota, Pennsylvania and through the drought stricken Southern Plains.

Many of these producers were under considerable strain in 2010 when gas ranged at the $5.50 – 4.00 MMBtu levels (lower at times). Look, for instance at Peyto Exploration (PEY.UN-TSX) (PEYUF.PK), a low cost gas producer based out of Toronto.

Peyto showed in Q4 2009 that they received an average of $6.17 MMBtu (with spot price lows ranging around $4.50) for their gas, but still had to raise money to support operations. Following Q1 2010, Peyto announced that it would have to raise $65 million through and equity issue...dilution of shareholder value.

Only yesterday, Nymex gas exploded to the bottom by 12.2 cents to $2.548 at 10:59 a.m. in New York. This result followed a week of declines brought on by bearish speculation of a damaging supply glut. Today, Nymex nat gas closed at $2.472 on the February contract and the March contract at $2.516. March portends the close of the heating season and the beginning of supply accumulation. Note the weak spread suggesting little influence of supply on price.

According to the U.S. Energy Information Administration's January “Short Term Energy Outlook”, a reason can be seen why sustained supplies are being priced into the market. According to the EIA, production volumes coming from U.S. Shale formations in 2011 increased by 4.5 Bcf/day year over year. This is a record. Further, EIA expects production to increase in 2012 by 1.4 Bcf/day, and in 2013 by .70. Inventories are also at all-time highs. At the end of 2011, working natural gas inventories penciled in at 3,472 Bcf, a record for this time of year. To account for supply increases versus a low demand heating season, EIA reports that storage experienced a draw of only 95 Bcf for week ended January 6, 2012 versus a five year average draw of 128 Bcf.

What counters the EIA's data is their own expectation of pricing going forward. EIA informs that Henry Hub spot prices will average $3.53/ MMBtu in 2012 (under the $4.50 previously predicted), and $4.14 in 2013.

Burn up of perspective

The monocle of time can put this data into perspective. Today, at the American Energy Resources Summit at Rice University, the CEO and Chairman of ConocoPhillips looked through the front window, as opposed to the rear view mirror. James Mulva offered that in the 1980's, the sun was setting on the nat gas industry, due to falling demand and decreasing reserves. He pointed out that U.S. reserves bottomed in 1993 at 162 Tcf, equating to an eight year reserve based on consumption, and the lowest reserves since 1946. In 1946 technology for gas capture wasn't even developed, let alone horizontal drilling.

Mr. Mulva continued by saying that reserves are now up by 68% and that the EIA now estimates reserves at 2,700 Tcf. 

Looking at today’s newly found “ocean of gas”, it appears that North America must be in search of either new markets for this ocean, or simply curtail production. New markets do exist, and consist primarily of foreign markets paying well over U.S. prices for liquefied natural gas (LNG).  But this requires the firms that imported nat gas in the “sunset years” to retool and reverse their terminals in order to export as opposed to import.

Explosively new market

Cheniere energy (LNG) appears to be taking a lead to the global LNG market. Cheniere is renovating their Sabine Pass, Louisiana import plant and has announced four long term supply contracts. The most recent one being a 20 year contract with BG Group, Inc. based in Berkshire, England. Moreover, Cheniere is planning to “reverse” another terminal, this one in Corpus Christi, Texas. Both facilities are in the Gulf region, to serve European or Asian markets.

Reversing these Gulf terminals comes at a time when Japanese LNG consumption increased by 32% in December, 2011. A result of Japan’s nuclear industry suffering inconfidence and safety inspections due to the Fukishima disaster. The U.K. also has an issue by importing 40% more LNG year over year in the January through November, 2011 period. Of alarm is that for 2011, 90% of such imports came from Qatar, according to a January 16 report from Platts, citing Deutshe Bank. This 90% supply concentration compares with 44% of supplies coming from Qatar in 2009.

While the U.K.’s LNG consumption has dramatically increased, Argentina also showed a dramatic increase. In 2011, Argentina imported 2.9 mt of LNG, an increase of 142%. This contrasts with the country’s 2010 imports of 1.2 mt.

Should this data seem unusual, it appears to have support. Consider the long term rates for tanker transports reported on Tuesday. It appears that growing LNG demand from Europe, Asia and South America are pushing daily spot rates for LNG transport to records. $150,000 per day is the current rate in January to transport LNG. This compares with $125,000/day in December, 2011. Long term lease rates were also driven up to a new record, by Japanese firm Tokyo Electric Power Co. (TEPCO), a firm associated with the Fukoshima disaster. They contracted for a three year charter with Golar LNG for $137,000/day, while rates range from $143,000 to $155,000/day. Golar spot target is $198,000/day.

Capacity to transport the LNG is not keeping pace with growing demand. Currently, over the next year, only 2 new tankers are expected to be deployed. Over the next two years, 10 tankers. That’s 12 tankers in 2013. At current prices, the market will respond. Some anticipate that the long term charter rates already price in some 30 to 40 new tankers being deployed in three year’s time. Ship yards should become profoundly busy.

Today in business

Evidently, new markets do seriously exist for U.S. nat gas, but it must be transformed into LNG so that it can be transported outside a pipeline. And, as said earlier, Cheniere Energy has the lead on that pursuit. Development of infrastructure in the U.S. is a first necessary step. That is, aside from our existing pipeline shortage domestically (look at the LNG market in New England, Keystone issues effecting all dynamics), one must consider reversing our LNG terminals to export, as opposed to import. Most such terminals that exist, for sooner than later deployment, are in the Gulf, leading to higher shipping charges due to tanker rates. Is this our dilemma in the global market?

Let’s see…Cheniere is leading the cause to open new markets to U.S. exports. Such markets that were heretofore unknown, but with all the potential being on the profit side of the supply and demand balance.  Yet, Cheniere has a debt burden of $3B, while the U.S. has so much of the gas (high GOR wells are restricted from flaring ). 

On the West coast, up north in Canada, we can see a formation of partners. Royal Dutch Shell, China  National Petroleum Corp., Korea Gas Corp. and Mitsubishi are all looking to build an LNG export facility in Kitmat, British Columbia.  They hope to be operational by 2015-2017 and expect to supply Asia with 800 mmcft/day. A second project is planned, also in Kitimat involving Apache Corp., EOG Resources Inc. and Encana Corp. Their plans are not as complete.

While these plans continue in the U.S. and Canada to arbitrage price differentials, Australia has her own project.  Australia’s Total SA and Japan’s Inpex Corp. received approval to build a $34B (usd) export plant over 5 years . This joint venture seeks to serve Japan and Asia.

However, there does appear to be a comparative advantage to the west coast LNG producers versus Australian producers. This advantage is due to geography. It is a difference between the shores of Australia versus Canada’s West Coast. From Australia to Japan, 4,400 nautical miles exist by thumb measure, while Canada to destination is 4,200. Based on current tanker charges, 200 miles could save 2 days fees…..

Save for this new, exciting and competitive market, how does North America burn its gas? By cutting production? That’s the next topic on this issue.

R. McWilliams