EIA: Mexico's Energy Ministry Projects Rapid Near Term Growth of Natural Gas Imports from U.S.

 A combination of higher natural gas demand from Mexico's industrial and electric power sectors and increased U.S. natural gas production has resulted in a doubling of U.S. pipeline exports of natural gas to Mexico between 2009 and 2013. Mexico's national energy ministry, SENER, projects that U.S. pipeline exports to Mexico will reach 3.8 billion cubic feet per day (Bcf/d) in 2018. This would be more than double U.S. pipeline exports to Mexico in 2013, which averaged 1.8 Bcf/d. This projected growth is driven mainly by higher demand from Mexico's electric power sector in both the north and interior of the country.



Nearly three quarters of the projected growth in Mexico's natural gas consumption between 2012 and 2027 is projected to occur in the electric power sector (see graph). This growth is largely driven by private and independently operated power plants, whose natural gas consumption is expected to rise at a 7.9% average annual rate, from 1.6 Bcf/d in 2012 to 4.9 Bcf/d in 2027. By contrast, natural gas consumption from plants operated by national energy company CFE grows at just 0.4% per year, from 1.1 Bcf/d in 2012 to 1.2 Bcf/d in 2027. The growth comes largely from new combined cycle plants, which benefit from greater operational efficiencies and lower emission levels compared to other generation sources. Growth sharply accelerates over the near term but continues through 2027, when power sector consumption reaches 58% of total gas consumption, compared to 47% in 2012.

Mexico's projected growth in natural gas consumption occurs in each of its five market regions: Northeast, Northwest, Interior-West, Interior, and South-Southeast. According to SENER, demand growth is particularly strong in the northern and interior regions of the country.



All natural gas pipeline imports from the United States into Mexico enter the country's Northeast and Northwest regions. Some of these imports enter the country as logistical imports on pipelines owned by private entities, as well as by Pemex's natural gas subsidiary PGPB. The term logistical imports refers to imports that arrive in areas with no other form of access to natural gas. The largest growth in projected pipeline imports takes place from nonlogistical imports on PGPB owned pipelines in the Northeast. An increasing portion of this gas flows through the Northeast south to the interior regions, but much of it also serves increased consumption from the Northeast's industrial and electric generation facilities. Higher natural gas pipeline imports from the United States into the Northeast region meet both higher demand from consumers there and the increased pipeline flows from the Northeast to regions further south.

About three quarters of Mexico's natural gas production comes from associated gas that is produced at Pemex's offshore oil platforms in the South-Southeast region. Natural gas production in the South-Southeast is expected to grow by only 0.4% per year through 2019. Pemex consumes increasing amounts of this production in the near term for its exploration, production, and refining activities. With stagnant growth in the production of associated gas in the South-Southeast and limited capacity for future growth in LNG imports, pipeline imports from the United States become the primary means for Mexico to satisfy national demand growth.

SENER has previously made projections that assumed more robust investment in the development of new gas fields, and a more aggressive and diverse range of well productivity rates. SENER's high natural gas production growth projections included the undertaking of an initiative to enhance recovery rates in the South-Southeast of both gas and oil extracted from offshore fields in the Yucatan Peninsula, as well as development in the Northeast of the Sabinas Basin's La Casita shale gas play and Mexico's portion of the Eagle Ford shale play.

However, there are significant factors that could inhibit the development of shale gas and other basins in Mexico, including the geologic complexity and discontinuity of its shale gas areas, the availability of required technology and water resources, security concerns, and a focus on development of crude oil resources. Even if additional development did occur, Mexico's northern regions would likely still see high growth in pipeline imports from the United States, particularly in areas that lack pipeline connectivity to other parts of the country.

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Energy Outlook: What’s Hot in 2014

By Marin Katusa, Chief Energy Investment Strategist

Investors who want to know how the energy sector will be doing in the coming year are, in my opinion, asking the wrong question. There really is no such thing as "the energy sector," because the performance of the different resources—from oil and gas, to uranium, to coal, to renewables—can vary dramatically.


Case in point: while unconventional oil exploration and production have seen a huge upswing in recent years, thanks to the vast success of the Bakken and other oil rich shale formations, at the same time natural gas has taken a nosedive, due to a supply glut that still hasn't found its balancing point.

To find out which investments will deliver the greatest profits for well positioned investors in 2014, my team and I have identified three trends that are hot… and may become even hotter in the course of this year.

HOT: Service Companies in North America

The oil and gas production in the United States is mature. Rather than looking for new basins, companies are looking to "rediscover" the past by applying new technology to increase economic production from known oil and gas fields.

This new technology comes in a variety of shapes and sizes: better software, bigger rigs, more efficient drilling processes. And it's being applied everywhere, onshore and offshore, conventional and unconventional alike.

Just as an example, today we're seeing operators drill more than 50 horizontal wells from a single well pad, a far cry from just a decade ago.

Exploration and production companies know that the focus moving forward is not just the amount of oil they can pump out of the ground, but the profit they can extract from every barrel (what we call the "netback"). This is even more true in the mature unconventional basins such as the Bakken, Eagle Ford, and the Marcellus shale plays, where the margins are tight and require an oil price of more than US$70 per barrel in order to be economic.

This means E&P companies have to use the best ways to increase production from every well—while at the same time reducing their drilling costs. Failure to do so would be to guarantee a firm's demise.

The dilemma for E&P companies is having to prioritize what their shareholders want in the short term—growing production and dividends—over whatever may be best for the company in the long term. At the same time, they have to fight the natural decline of oil coming out of their wells.

All the while, service companies continue to extract fees for their tools and services. Drillers, pumpers, frackers, and other oilfield-service guys make money regardless of whether E&P companies find oil or produce it at economic rates.

We've said it before: Many E&P companies are running on a treadmill, and the incline is going higher and higher, which means higher costs to produce the same amount of oil.

Of course, not all service companies will rake in the dough. The ones that will do the best are the ones that can consistently stay at the forefront of technology and keep signing contracts with the supermajors like Exxon, Chevron, and Shell.

HOT: European Energy Renaissance

Russia's grip on European energy continues to tighten, and there's a push to produce oil and gas within their own borders all around Europe.

2014 looks to be an exciting year for companies like one of our Casey Energy Report stocks, a TSX-V-listed oil and gas explorer and producer with a 2 million acre concession in Germany. We call the deposit it's sitting on the "Next Bakken" because we believe that its potential to deliver exceptional output could rival that of the famed North American formation.

This development is still in its early stages, but investors who position themselves now could see outsized gains for years to come. It's not really a question of "if" the oil is there—previous oil production in the very same location yielded more than 90 million barrels—but of "how much" oil can be extracted with the modern methods not available the last time companies worked on this field.

The company has completed its first well and will continue to drill additional wells (both vertical and horizontal) next year. While the initial well cost more than anticipated, it's a good start that indicates economic oil can be produced in Germany. We're also confident this company's experienced management team is applying the lessons of its first foray to reduce drill costs on future wells.

As our Energy Report pick proves up any of its projects in 2014 and early 2015, we can expect another of our holdings, which has just entered the German oil and gas scene, to either farm into the company or even buy it out.

We predict that by the end of 2015, our "Next Bakken" play, and others like it, will have attracted a lot of attention, not just from individual speculators, but from institutional investors as well—and investors who have gotten in early will be very happy indeed.

Another of our portfolio holdings is just beginning to drill on its Romania projects after a series of delays due to politics and bureaucracy. We have reason to be optimistic because its JV partner, a Gazprom subsidiary, has drilled successful wells on the same basin on the other side of the border in Serbia. If our pick has anything close to that level of success, the markets will surely take notice and its shares will go much higher.
As the "Putinization" of the global energy markets continues and Russia's dominance grows, European countries become increasingly more desperate to escape from under Putin's heavy thumb and to start developing their own energy resources.

The European Energy Renaissance is real, and we continue to monitor companies that are funded and have the permits and ability to drill game-changer wells in Europe in 2014.

HOT: Uranium

During a recent trip to London, I spoke with Lady Barbara Judge, chairman emeritus of the UK Atomic Agency and an advisor to TEPCO on the Fukushima nuclear disaster in Japan. I asked her point blank whether Japan was willing to bring any nuclear reactors back online in 2014.

Her answer was an unequivocal "Yes." The Japanese have no choice, really, because the alternative—importing liquefied natural gas (LNG)—is far too expensive.

Japan is the world's largest importer of LNG and has had to double its imports since the Fukushima incident. For that privilege, the country pays some of the highest rates on the planet, almost four times more than what we pay for natural gas in North America.

South Korea also shut down its nuclear plants post-Fukushima to do inspections and maintenance upgrades, and it, too, has had to import a lot of LNG. Both countries are looking to restart their nuclear reactors so they can stop paying a fortune to foreign energy suppliers. When these countries restart their reactors, they'll also restart the uranium market, so we expect uranium prices to begin to shake loose of the doldrums this year.

Another driver will be throwing the switch at ConverDyn, the U.S. uranium facility that is slated to start converting natural U₃O₈ to reactor-ready fuel in late 2014 or early 2015.

We currently hold two solid uranium companies in the portfolio—one is a U.S. based small cap producer (one of the very few in America), the other is the lowest risk way to play the uranium market that I know of. Both, we believe, will take off in 2014 on the renewed interest in uranium and the associated stocks.

If you want to know more about our thoroughly vetted energy stocks and their potential for amazing gains in 2014 and beyond, give the Casey Energy Report a try. You'll find all my "What's Hot" predictions and the full names of the stocks I've mentioned above in our January forecast issue… plus the energy sectors you should avoid like the plague this year… as well as a feature article on elephant oil deposits in the Gulf of Mexico and a new stock pick ready to profit from them.

Giving the Casey Energy Report a try is risk-free because it comes with a 3 month, full money back guarantee. If the Energy Report is not all you expected it to be, just cancel within those 3 months and get a prompt, full refund. Or cancel any time AFTER the 3 months are up for a prorated refund. Getting started is easy.......Just Click Here.


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Baker Hughes Announces Fourth Quarter 2013 Well Count

Baker Hughes Inc. (NYSE: BHI) announced today that the U.S. onshore well count for the fourth quarter 2013 is 9,056 wells; down 19 wells from the revised 9,075 wells counted in the third quarter 2013. Compared to the fourth quarter 2012, the well count was up 398 wells or 5%. Due to improved drilling efficiencies, the average US onshore drilling rig now produces 9% more wells compared to the same quarter last year.

Compared to the third quarter 2013, the well count increased most notably in the Eagle Ford (up 75 wells or 7%), Mississippian (up 23 wells or 6%) and Marcellus (up 21 wells or 4%) basins. These increases were offset by reductions in the Fayetteville (down 29 wells or 18%) and Granite Wash (down 22 wells or 13%) basins.

The average US onshore rig count for the fourth quarter 2013 was down 12 rigs from the previous quarter at 1,697 rigs. On average, the US onshore rig fleet produced 5.34 new wells during the fourth quarter, representing a 1% improvement in drilling efficiencies compared to the third quarter.

For more detailed Well Count information by basin, including historical well counts and a map, visit www.bakerhughes.com/wellcount.

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Decoding the mystery behind Shell's shale write down

The Market Currents staff at Seeking Alpha is shedding some light on the huge write down by Shell this week. Is the U.S. oil boom over hyped?

Shell's (RDS.A) $2.1B write down on its North American shale oil exploration acknowledges some of its spending there will not prove economically viable, and that hitting its cash flow targets could get tougher. Adding to the mystery is Shell's refusal to identify which shale formation has taken the write down or to explain the charge.

Shale skeptics might take the write down as first evidence the U.S. oil boom is overhyped, but WSJ's James Herron thinks it more likely that Shell has "just failed to get lucky" - Eagle Ford, where Shell has significant operations, is well known for its “sweet spots,” which yield greater volumes of the prized liquids compared with gas.

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Murphy Oil Corp. Reports 2nd Quarter 2013 Earnings

Murphy Oil Corporation (NYSE: MUR) announced today that net income was $402.6 million ($2.12 per diluted share) in the 2013 second quarter, up from $295.4 million ($1.52 per diluted share) in the second quarter 2012. Net income in the 2013 quarter included income from discontinued operations of $70.5 million ($0.37 per diluted share) compared to income from discontinued operations of $4.1 million ($0.02 per diluted share) in the 2012 quarter.

The 2013 income from discontinued operations was primarily generated by an after tax gain of $71.9 million from sale of the Mungo and Monan fields in the United Kingdom during the just completed quarter. Income from continuing operations was $332.1 million ($1.75 per diluted share) for the 2013 second quarter compared to $291.3 million ($1.50 per diluted share) in the same quarter of 2012.

The results of continuing operations improved in 2013 primarily due to higher earnings in the U.S. oil and gas business, which was attributable to growth in oil production in the Eagle Ford Shale area in South Texas.

Read the entire Murphy Oil Corp. earnings report.


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Kinder Morgan Completes Acquisition of Copano Energy KMP CPNO

COT fund favorite Kinder Morgan Energy Partners (NYSE: KMP) today closed its previously announced acquisition of Houston based Copano Energy (NASDAQ:CPNO). KMP has acquired all of Copano’s outstanding units for a total purchase price of approximately $5 billion, including the assumption of debt. The transaction, which was approved by the Copano unitholders on April 30 (with more than 99 percent of the units that voted voting in favor of the transaction) and previously by the boards of directors of both companies, is a 100 percent unit for unit transaction with an exchange ratio of .4563 KMP units per Copano unit.

“We are delighted to complete this transaction, which will enable us to significantly expand our midstream services footprint and offer a wider array of services to our customers,” said KMP Chairman and CEO Richard D. Kinder. “We will now pursue incremental development in the Eagle Ford Shale play in South Texas, and gain entry into the Barnett Shale Combo in North Texas and the Mississippi Lime and Woodford shales in Oklahoma. The transaction is expected to be modestly accretive to KMP in 2013, given the partial year, and about $0.10 per unit accretive for at least the next five years beginning in 2014”......Read the entire Kinder Morgan press release.


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EIA Weekly Natural Gas Update for April 4th

Marketed natural gas production in the Gulf of Mexico federal offshore region falls to 6% of national total in 2012. Continuing a long term trend of decline, the contribution of marketed production of natural gas from the Gulf of Mexico federal offshore region accounted for 6.0 percent of total U.S. marketed natural gas production (4.2 billion cubic feet per day (Bcf/d) in 2012, according to data published in the Energy Information Administration’s (EIA) Natural Gas Monthly. In contrast, in the period from 1997 to 2007, marketed production from these same waters provided, on average, over 20 percent (11.7 Bcf/d), of U.S. marketed production.




Among the contributing factors to this decline:

• Increasing amounts of domestic, on-shore production, primarily from shale gas and tight oil formations. In 2012, nearly 40 percent (over 26 Bcf/d according to Lippman Consulting, Inc.) of U.S. dry natural gas production came from production in shale plays, increasing over 20 fold from 2000 levels. In 2012, the two most productive shale plays were the Haynesville play in Louisiana and Texas, and the Marcellus play in Pennsylvania. In the Marcellus play, despite reduced drilling activity, production increased by almost 70 percent in 2012 over year ago levels. Increased drilling in tight oil plays like the Eagle Ford play in Texas has contributed to increased associated natural gas production. 

• Relatively low natural gas prices. Low natural gas prices in recent years have diminished the economic incentive for off shore natural gas directed drilling. However, relatively high crude oil prices continue to support oil directed drilling and the production of associated gas, particularly in deep waters. New large deepwater projects directed toward liquids development are projected to reverse the decline in natural gas production from the Gulf of Mexico in 2015, according EIA's Annual Energy Outlook 2013 Early Release.

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Geology and Technology Drive Estimates of Technically Recoverable Resources

A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source is the remaining technically recoverable resource (TRR). TRR estimates are a work in progress, changing as more production experience becomes available and as new technologies are applied to extract these resources. The greatest uncertainty is associated with the "estimated ultimate recovery," or EUR, per well.

EIA updates its TRR estimates using the latest available well production data. EIA's recently released Annual Energy Outlook 2012 (AEO2012) contains a detailed discussion of TRR estimates and resource uncertainty. AEO2012 projections also include sensitivity cases varying the EUR per well and a high-TRR case. The TRR estimates provide context for the size of the resource, while projected production depends strongly on the number of wells, the EUR per well, other well characteristics, and economics.

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TRR estimates consist of "proved reserves" and "unproved resources." As wells are drilled and field equipment is installed and productivity is assumed, unproved resources become proved reserves and, ultimately, production. The TRR estimate for a continuous-type shale gas or tight oil area is the product of land area, well spacing (wells per square mile), percentage of area untested, percentage of area with potential, and the estimated ultimate recovery (EUR) per well.

The Annual Energy Outlook 2012 unproved TRRs are shown in the figures above for the major shale gas and tight oil formations. The formation parameters that result in these TRR are provided elsewhere. The volume of total TRR due to proved reserves is not shown. "Tight oil" refers to crude oil and condensates that are produced from low permeability sandstone, carbonate, and shale formations. The tight oil TRRs are for the entire formation, including the non shale portions.

Read the entire article at EIA.Com

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Rising Production in the Permian Basin

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The Permian Basin, a long time oil and natural gas producing region in west Texas and eastern New Mexico, is showing signs of new life. The active rig count has grown from 100 rigs in mid 2009 to over 500 rigs in May 2012. According to data from the Texas Railroad Commission and the New Mexico Energy, Minerals and Natural Resources Department, oil production from the Permian has increased fairly steadily over the past few years, reaching the 1 million barrels per day (bbl/d) threshold in late 2011, the first time since 1998.

Sources: U.S Energy Information Administration, based on Baker Hughes, Railroad Commission of Texas, and New Mexic

Growing oil production in the Permian Basin and other Texas plays, most notably the Eagle Ford shale, may be starting to strain existing takeaway capacity and is creating a need for Texas oil to serve more distant refineries. While new pipeline projects are scheduled to come online, current transportation constraints have caused Permian crude oil, which is priced in Midland, Texas, to sell at a significant discount to WTI beginning in January 2012.

EIA: Eagle Ford Oil and Natural Gas Well Starts Rose Sharply in First Quarter 2012

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New well starts in the Eagle Ford region in Texas increased 110% from January through March 2012 compared to the same period in 2011, according to reporting and analysis by BENTEK Energy LLC (Bentek).



Other key findings include:

Operators started drilling (spudded) 856 new wells in January through March 2012 compared to 407 in January through March 2011.

In early April 2012, the Eagle Ford active rig count set a new high of 217 units.

Increased drilling and rig deployment translated into higher crude oil and condensate production, which is projected to average over 500 thousand barrels per day (bbl/d) in April, up from 182 thousand bbl/d in April 2011.

Current Eagle Ford area natural gas production is about two billion cubic feet per day.

Horizontal wells accounted for nearly all of the new well starts so far in 2012.

Much of the drilling activity in the Eagle Ford is targeting both crude oil and wet natural gas resources.

Bentek estimates that in March 2012, Eagle Ford crude oil and lease condensate production was approaching crude oil production in the North Dakota part of the Bakken formation.

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