New LNG Plant in North Dakota will Supply Oil and Gas Producers

A new natural gas liquefaction plant is slated to come online this summer in North Dakota to reduce the flaring of gas in the Bakken Formation and provide fuel for Bakken oil and gas operations. The developer, Prairie Companies LLC subsidiary North Dakota LNG, announced earlier this month that the plant would provide an initial 10,000 gallons per day (gal/d) of liquefied natural gas (LNG), and could expand to 66,000 gal/d. Assuming a 10% processing loss, the plant would take in a maximum of 6 million cubic feet per day (MMcf/d) once expanded. In 2012, North Dakota vented and flared 218 MMcf/d of natural gas because of record high oil production and insufficient pipeline takeaway capacity for natural gas produced as a byproduct.

Hess Corporation will supply the natural gas for liquefaction at Prairie's Tioga natural gas processing location. After the LNG is produced, it will be sent via truck to storage sites at drilling locations, where – once regasified – it can be used to power rigs and hydraulic fracturing operations as well as LNG vehicles. LNG itself cannot burn; in its liquefied state, its temperature is minus-260 degrees Fahrenheit. However, as a liquid, it takes up only 1/600th of its volume as a gas, so LNG is an excellent form to store or transport natural gas. Currently, most drilling operations run on diesel, and converting to natural gas provides potentially significant cost savings given the current differential between diesel and natural gas prices. In 2012, EIA estimated that nationally oil and gas companies consumed more than 5 million gal/d of diesel in their operations, representing a significant expense.

While conversion to natural gas might not be possible in many cases, in the past few years, several companies have developed and are marketing technologies that would allow drilling rigs and fracturing pumps to run in both dual fueled and or single fueled modes.

Although the liquefaction plant will be the first LNG project in the Bakken, some producers have begun using natural gas to power their operations, citing cost savings, access to natural gas, and environmental benefits. Statoil uses compressed natural gas (CNG) to fuel some of its drilling equipment. The natural gas is produced in the Bakken and compressed using General Electric's CNG in a Box system.

Additionally, outside of the Bakken, other companies have successfully used natural gas to power drilling operations. In 2012, Seneca Resources and Ensign Drilling installed GE LNG fired engines on drilling rigs in the Marcellus Shale. Apache, Halliburton, and Schlumberger have successfully used CNG and LNG to power hydraulic fracturing operations in the Granite Wash formation in Oklahoma.

Some of these companies have estimated fuel savings on the order of 60% to 70% compared to diesel, as well as payback on the conversion investment in about a year. The basic economics that have driven the recent interest in converting or manufacturing more heavy duty trucks to run on LNG are driving some of the interest in converting to natural gas for fueling stationary oil and gas operations.

Posted courtesy of the EIA


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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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Cabot Oil & Gas raises 2013 production growth guidance view to 50%-55%

Cabot Oil & Gas (COG) says it recently achieved a new gross production record in the Marcellus shale of 1.5B cf/day, prompting it to raise its 2013 production growth guidance range to 50%-55% from 44%-54%; 2014 production growth guidance remains unchanged at 30%-50%.

COG also agrees to provide 350M btu/day of natural gas to the Dominion Cove Point LNG Terminal for 20 years commencing on the project's in-service date scheduled for 2017.

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The Energy Report: Micro-Cap Oil Stocks that Hit the Jackpot

The Energy Report: With oil prices firming up over the past couple of months and the spread between West Texas Intermediate (WTI) and Brent Crude narrowing, what are your price expectations for the remainder of 2013 and into next year?

Phil Juskowicz: While I don't spend a lot of time predicting commodity prices, I personally see relatively stable short-term oil prices. Intermediate or long-term prices may weaken, assuming no supply disruptions arise from political upheavals, while gas prices may strengthen based on supply/demand fundamentals. We've seen continued oil supply growth and the short term market seems to be pretty range bound, having developed a good base around the $100 per barrel ($100/bbl) level.

TER: Where do you see some of the best investment opportunities in the oil and gas business?


PJ: Micro-cap exploration and production (EP) stocks have severely underperformed the SP Small Cap EP Index since the second half of 2011 (H2/11). However, the definition of "small cap" depends on who you're talking to. The Small Cap EP Index consists of companies around the billion-dollar range like Approach Resources Inc. (AREX:NASDAQ) and Northern Oil Gas Inc. (NOG:NYSE). Casimir has a micro-cap EP index, which is comprised of companies with market caps up to $500 million ($500M) with some names under $100M. That index level started to diverge in H2/11. Both of these groups consist of relatively equal gas/oil weightings, so the performance should not, in our opinion, be attributed to the relative strength of oil prices over gas that commenced around that time. As a result, we believe that there are attractive investment opportunities in the micro-cap EP universe.

Casimir Micro-Cap EP Index (White) vs. SP Small-Cap EP Index (Yellow)


Casimir Micro-Cap EP Index composed of: AMZG, ANFC, CAK, CPE, CXPO, EGY, EEG, ENRJ, ENSV, FEEC, FXEN, GMET, GNE, HDY, HNR, IFNY, IVAN, LEI, MCEP, MILL, MPET, MPO, OEDV, PHX, PNRG, PSTR, RDMP, SARA, SSN, STTX, TAT, TENG, TGC, TPLM, USEG, WRES, ZAZA
Source: Bloomberg; Casimir Capital

TER: How do you choose the companies in your coverage list?

PJ: We look for small companies that have largely flown "under the radar screen" and are underfollowed. The companies we cover have strong management teams and operate in premier areas with good assets that have substantial cash flow potential.

TER: Do you cover any service companies?

PJ: Enservco Corp. (OTCBB:ENSV) is on our "watch list". The company is the only nationwide provider of hot oiling, well acidizing and frack heating services generally used to coax oil out of the ground, for example to counter paraffin buildups. Enservco experienced healthy margins in Q2/13 despite it typically being a seasonally weak time for heating services. The company continues having to turn customers away in some areas while it builds out its fleet. Management, in our opinion, has a track record of building successful companies and its regional staff has strong relationships with EPs. The company is also expanding into other basins and successfully tapping into new revenue sources.

TER: Why aren't competitors seeing the opportunity here and moving in to get a piece of the action?

PJ: There are regional pockets of mom and pop shops that will do some of these services, but, a nationwide company like a Noble Energy Inc. (NBL:NYSE) might turn to Enservco because it already has a reliable relationship with Enservco's staff in different areas. Enservco's services account for a very low percentage of total well drilling and completion costs (it might cost around $100,000 to service a $7M well) so customers are not as likely to conduct competitive bidding processes. Instead, they choose to use a company with which the frontline managers already have existing relationships.

TER: So it has developed a national reputation, which is its competitive strength.

PJ: And it's building out the capacity as we speak. Enservco is expanding its already large presence in the Marcellus Formation. In its Q2/13 conference call, management said they were starting to see the Utica play out a little bit. The Utica underlies the Marcellus in a lot of areas and Enservco gets some economics of scale there. [See map] Furthermore, management has been getting the word out more and also may be contemplating a reverse stock split and listing on another exchange.


Source: Marcellus Coalition

TER: What EP names on your coverage list look interesting?

PJ: We like Miller Energy Resources (MILL:NYSE; MILL:NASDAQ), which, in late 2009, captured former Pacific Energy Resources Ltd. assets out of bankruptcy that were valued at $500M for an outstanding $4.5M. Miller's entire enterprise value, meanwhile, is just $240M. Moreover, its infrastructure assets were valued by third parties on behalf of its lender at $190M. What makes these assets most attractive is the fact that recent well results indicate that original estimates by Forest Oil (which sold the properties to Pacific in 2007) may in fact be correct, which would mean that these Alaskan assets could contain 100200 million barrels (MMbbl) of recoverable oil reserves. Proved oil reserves presently stand at 8.61 MMbbl.

TER: How was Miller able to buy $500M worth of assets for less than 1% of their value? Even in bankruptcy, you'd think that there'd be buyers willing to pay more than that.

PJ: David Hall, a Miller Energy executive who had worked on the assets even before Pacific bought them from Forest Oil in 2007, was following the Alaskan bankruptcy proceedings. He got in touch with the CEO of Miller, Scott Boruff, and told him about these assets that were becoming available.

TER: Why does Miller believe that the original estimates of recoverable oil reserves may, in fact, be correct?

PJ: The thesis is that Forest Oil used the wrong completion techniques, which is why well performances had dropped off. The completion techniques Forest Oil used were in fact different from techniques used for other assets on the McArthur Trend. David Hall believed that workovers on existing wells, for example, replacing some electric submersible pumps and making changes to completion techniques on new wells, could improve production. Low and behold, that's exactly what's happened.
In addition, Miller just started doing sidetracks of some of these old wells. It posted a 21-day production test of its RU-2A well several weeks ago at 1,314 barrels per day, which would indicate that that the oil's there and it's recoverable. Management has been doing a good job of utilizing preferred equity to have substantial capital expenditure programs without diluting the common shareholders. To top it off, it has about 600,000 undeveloped acres that it's just starting exploration on as well.
TER: What other names look interesting?

PJ: I like Trans Energy Inc. (TENG:OTCBB), which is a pure play in the Marcellus Shale. The company holds about 20,000 net acres in the Marcellus, a substantial portion of which are in the core, liquids-rich part of the play. Operators, including Range Resources Corp. (RRC:NYSE), EQT Corp. (EQT:NYSE) and Gastar Exploration Ltd. (GST:NYSE), continue to increase their return assumptions for acreage adjacent to Trans Energy's. The company's production is set to ramp up as soon as Williams Companies Inc. completes the construction of certain infrastructure. Trans Energy's acreage is in northeast West Virginia, on the southwest Pennsylvania border. There's been a lot of success coming out of that area.

TER: What sort of strategy would you suggest our readers consider?

PJ: I think the micro-cap space, in general, is less correlated to the market's vagaries. Perceived changes in foreign interest rates, for example, have a larger effect on large-cap names. Micro-cap pricing is determined more by company-specific dynamics, such as anticipated future cash flows. Plus, a lot of micro-cap names and EPs in general seem to be more active on hedging, and therefore should be less susceptible to changes in commodity prices. As a result, investors that exercise due diligence should be rewarded for accurate cash flow predictions. If you want to find companies where your hard work can actually pay off, then the micro-cap space is a good place to look.

Micro caps seem to be getting more active in reaching new investors, and some of the management teams have regrouped from previous lives and are starting up very successful new companies. I think Bonanza Creek Energy Inc. (BCEI:NYSE) is a great example of management hailing from one company and getting back together and starting all over again.

TER: Thanks for talking with us today and giving us some interesting input, Phil.

PJ: I appreciate the opportunity.

Philip Juskowicz, CFA is a managing director in the research department at Casimir Capital, a boutique investment bank specializing in the Natural Resource industry. Juskowicz began his career at Standard Poor's in 1998, where he was one of the first analysts to recommend Mitchell Energy, credited with discovering the Barnett Shale. From 2001-2005, He worked with a former geologist in equity research at both First Albany Corp. and Buckingham Research. At Buckingham, Juskowicz was promoted to a senior oilfield service analyst position, leveraging his extensive knowledge of the EP space. From 2006-2010, he was an insider to the oil and gas industry, serving as a credit analyst at WestLB, a German investment bank. In this capacity, Juskowicz was responsible for $500M of loans to energy companies and projects. He earned a Master of Science in finance from the University of Baltimore.

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More earnings....Cabot Oil and Gas [COG] and Hess [HES]

Cabot Oil & Gas Corporation (NYSE: COG) today reported its financial results for the first quarter of 2013. Highlights for the quarter include:

*    Production of 89.3 billion cubic feet equivalent (Bcfe), an increase of 50 percent over last year's comparable quarter and 13 percent over the fourth quarter of 2012.
*    Net income of $42.8 million, or $0.20 per share.
*    Net income excluding selected items of $54.2 million, or $0.26 per share.
*    Cash flow from operations of $212.7 million and discretionary cash flow of $234.4 million.

"The success of our drilling program in the Marcellus continues to drive record operating and financial metrics for the Company, including all-time highs for quarterly production, revenues, operating cash flows and discretionary cash flows, despite historically low realized natural gas prices," said Dan O. Dinges, Chairman, President and Chief Executive Officer......Read the entire Cabot Oil and Gas earnings report.

Hess Corporation (NYSE: HES) today reported net income of $1,276 million for the quarter ended March 31, 2013. Adjusted earnings, which exclude gains on asset sales and other items affecting comparability of earnings between periods, were $669 million, or $1.95 per common share, representing a 30 percent increase on a per share basis over the same quarter last year.

The Corporation generated net cash flow from operations of $819 million during the first quarter while reducing capital and exploratory expenditures by $355 million, a reduction of 18 percent in the year over year period. The Company continues to make progress on its asset sales.

In the first quarter, the Corporation completed the sales of its interests in the Beryl area fields in the United Kingdom North Sea, the Azeri-Chirag-Guneshli (ACG) fields in Azerbaijan, and announced the sale of its acreage in the Eagle Ford shale play in Texas, relieving Hess of approximately $500 million of future capital requirements over the next three years......Read the entire Hess earnings report.



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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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Where is all the new Natural Gas Pipeline Construction?

U.S. natural gas pipeline capacity investment slowed in 2012 after several years of robust growth. Limited capacity additions were concentrated in the northeast United States, mainly focused on removing bottlenecks for fast growing Marcellus shale gas production. More than half of new pipeline projects that entered commercial service in 2012 were in the Northeast (see map below). Excluding gathering, storage, and distribution lines, project sponsors in the United States added 4.5 billion cubic feet per day of new pipeline capacity and 367 miles of pipe totaling $1.8 billion in capital expenditures in 2012.




Read the entire EIA article


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EIA: Pennsylvania Natural Gas Production Rose 69% in 2012 Despite Reduced Drilling Activity

Natural gas production in Pennsylvania averaged 6.1 billion cubic feet per day (Bcf/d) in 2012, up from 3.6 Bcf/d in 2011, according to Pennsylvania Department of Environmental Protection (DEP) data released in February 2013. This 69% increase came in spite of a significant drop in the number of new natural gas wells started during the year.

Several factors contributed to the production increase. While accelerated drilling in recent years (primarily in the Marcellus Shale formation) significantly boosted Pennsylvania's natural gas production, increases were restricted by the state's limited pipeline and processing infrastructure. This created a large backlog of wells that were drilled but not brought online. As infrastructure expanded, these wells were gradually connected to pipelines, sustaining natural gas production increases through 2012 despite the decline in new natural gas well starts. Data from DEP show that a significant portion of wells that began producing in 2012 were drilled earlier.

 

Improved drilling and well completion techniques can reduce drilling time and lead to higher production per well. The increased use of horizontal drilling (see graph) and hydraulic fracturing, particularly in the more geologically favorable portions of the Marcellus, allows for more production per well. As operators continue to improve well completion techniques, they are achieving higher initial per-well production rates and boosting overall production.

Pennsylvania typically releases major production data twice a year for unconventional (horizontal) oil and natural gas wells and once a year for conventional oil and natural gas wells. With rapidly increasing natural gas production in Pennsylvania, EIA has proposed to add Pennsylvania (and at least 11 other states) to its monthly EIA-914 natural gas production survey, which would provide more timely reporting of Pennsylvania's rising production.

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Spot Natural Gas Prices at Marcellus Trading Point Reflect Pipeline Constraints

How To Position Yourself for a 10 Year Pattern Breakout

Daily natural gas spot prices between Tennessee Gas Pipeline (TGP) Zone 4 Marcellus and Henry Hub have diverged recently largely due to rising Marcellus production, which has outpaced the growth of available take away pipeline capacity in northern Pennsylvania. As a result, the spot price of natural gas at the TGP Zone 4 Marcellus trading point has fallen, at times considerably, below the spot price at Henry Hub in Louisiana, and is currently the least expensive wholesale natural gas in North America.

To address this rapid growth in natural gas production, several Northeast interstate pipeline projects were completed in 2011, adding nearly 1.5 billion cubic feet per day (Bcf/d) of capacity in Pennsylvania. Many additional pipeline projects have been proposed or are in various stages of completion in the Northeast to reduce transportation constraints caused by growing Marcellus natural gas production. EIA's website has information on the status of some of these pipeline projects.



Dry natural gas production in Pennsylvania, a key part of the Marcellus supply basin, continues to grow and according to Bentek Energy is now approaching 6 Bcf/d. Estimated June 2012 Marcellus dry natural gas production (5.7 Bcf/d) has nearly doubled since June 2011 (2.9 Bcf/d) and represents about 9% of overall U.S. dry natural gas production. Further, Bentek Energy estimates that there are over 1,000 natural gas wells that have been drilled in northern Pennsylvania but which are not yet producing natural gas because there is not enough interstate and gathering pipeline infrastructure to accommodate the new production.

Source: U.S. Energy Information Administration based on Bentek Energy, LLC.

Note: Reflects monthly averages of Bentek Energy's daily estimates of dry natural gas production for the state of Pennsylvania. These figures exclude a small amount of natural gas production received directly by local distribution companies and end users via gathering lines that are not subject to Federal Energy Regulatory Commission posting requirements for interstate natural gas pipelines.     

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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.

.

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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EIA: Market Changes Contribute to Growing Marcellus Area Spot Natural Gas Trading

Marcellus-area spot natural gas trading (InterContinentalExchange (ICE) day-ahead transactions) has more than doubled from under 1 billion cubic feet per day (Bcfd) to almost 2 Bcfd on average since 2005 (see chart). The largest gains in Marcellus area trading volumes were at the Tetco M3 trading point, up 178% to 0.5 Bcfd and at the Dominion South trading point, up 168% to 0.7 Bcfd since 2005. Key factors likely contributing to increased natural gas spot trading in the Marcellus area include: rapid increases in Marcellus shale gas production; direct deliveries of Wyoming gas to the Ohio/Pennsylvania border through the Rockies Express Pipeline; and increased use of natural gas for power generation.

Source: U.S. Energy Information Administration, based on Ventyx's Energy Velocity Suite.

Note: New Marcellus in the graph includes the Leidy, TGP 219, TGP 313, and TGP Zone 4 Marcellus trading points. 2011 includes data through November.

 Several factors are likely contributing to increased natural gas spot trading in the Marcellus area:

• Marcellus production gains. Bentek Energy, LLC estimates that Marcellus natural gas production now exceeds 4 Bcfd, up significantly in recent years.
• New trading points. In addition to several new Marcellus production area trading points, the extension of the Rockies Express Pipeline (REX) to Clarington, Ohio led to new natural gas trading points formed to facilitate commercial transactions. REX deliveries to Clarington, Ohio averaged over 1 Bcfd from January through December of 2011.
• Greater reliance on natural gas for electricity generation. Falling natural gas prices coupled with historically high spot coal prices created incentives for generators to use more natural gas to fuel their plants. Pennsylvania is one state that has seen significant growth in natural gas-fired electric generation.

Source: U.S. Energy Information Administration, based on Ventyx's Energy Velocity Suite. 

Ohio Shale Drilling Spurs Job Hopes in Rust Belt

A rare sight in hard-luck Youngstown, a new industrial plant, has generated hope that a surge in oil and natural gas drilling across a multistate region might jump start a revival in Rust Belt manufacturing. The $650 million V&M Star mill, located along a desolate stretch that once was a showcase for American industry, is to open by year's end and produce seamless steel pipes for tapping shale formations.

It will mean 350 new jobs in Youngstown, a northeast Ohio city that is struggling with 11 percent unemployment. V&M Star's parent company Vallourec, based in Boulogne-Billancourt, France, hopes increased interest in shale formations will produce a ready made market. Vast stores of natural gas in the Marcellus and Utica shale formations have set off a rush to grab leases and secure permits to drill. Industry estimates show the Marcellus boom could offer robust job numbers for 50 years.

Similar hopes are alive in Lorain, Ohio, where U.S. Steel will add 100 jobs with a $100 million upgrade of a plant that makes seamless pipe for the construction, oil-gas exploration and production industries. Erin DiPietro, a company spokeswoman in Pittsburgh, said the expansion will make the Lorain operation more competitive and help it tap into expanding shale developments.....Read the entire article.


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Marcellus Committee Clears Permit Fee Hurdle in West Virginia

Natural gas operators would pay $10,000 to drill a well in West Virginia's share of the Marcellus shale field, and $5,000 for each additional well at the initial site, under a proposal adopted Wednesday by a special legislative committee.

The House-Senate panel also approved provisions increasing bonds posted for well projects, enhancing public notice of drilling and compensating the owners of surface land where operators drill their wells. With the committee resuming its work next month, Wednesday's changes move lawmakers closer to a regulatory bill that they hope to propose during a special session before year's end.

But the permit fee amendment has been considered a crucial hurdle in the process. Operators now pay just a few hundred dollars for a permit. The resulting revenues have helped to leave the Department of Environmental Protection's Oil and Gas office with a $1 million shortfall in its budget.....Read the entire AP article.

Shale Gas Drilling Techniques Revolutionize Oil Shale Drilling

Colorado based BENTEK Energy reports that horizontal drilling and hydraulic fracturing, which has revolutionized U.S. shale gas production and other unconventional plays, is also transforming the domestic crude oil industry. As a result, U.S. oil production is on the rise for the first time in 23 years.

In its new report, The Rush to Unconventional Oil, BENTEK notes that technologies are being used to unlock oil from shales in a number of plays such as the Bakken and Niobrara shales in the Rockies region, the Bone Springs/Wolfberry, Granite Wash and Eagle Ford plays in and around Texas and the liquids rich shales in the southwestern Marcellus.

The most explosive growth is occurring in the Bakken shale in North Dakota, where production has grown 79 percent in the past year, or 114,000 b/d, compared to the five-year average of 144,000 b/d, boosting North Dakota past Louisiana as the nation's fourth largest oil producing state. As a result, the project for Rockies oil production based on the current rig count indicates 19 percent growth next year to 717,000 b/d. The U.S. Geological Survey.....Read the entire article.


The "Super Cycle" in Gold and How It Will Effect Your Pocketbook in 2010

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