Enbridge Energy Partners, L.P. on December 6 announced a further US$145 million investment to enhance the capability of its North Dakota crude oil system. The project will expand capacity into the Berthold terminal by 80,000 barrels per day (bpd) and will include a rail car loading facility at the terminal to accommodate the additional volume. The Partnership currently has contractual commitments for 70 percent of the rail loading capacity and anticipates it will soon finalize agreements for the remaining capacity.

"Our Berthold Rail Project complements a series of expansions Enbridge has undertaken to expand transport capacity from North Dakota. It integrates high quality Bakken crude into Enbridge's expanding portfolio of pipeline projects that access premium markets across the United States," said Mark Maki, President of the Partnership. "Importantly, it allows producers and shippers the ability to continue to grow their business while Enbridge develops the next phase of pipeline expansions on the Enbridge North Dakota System."

The Berthold Rail Project complements the Partnership's Bakken Expansion Program and integrates the Partnership's gathering pipeline capacity in western North Dakota and eastern Montana created by our Bakken Access Program with increased North Dakota export capacity.

The Bakken Expansion Program, which was announced in August 2010, will accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota and southeast Saskatchewan. The program is expected to add 145,000 bpd capacity, 25,000 bpd of which is already available; the remaining 120,000 bpd is expected to be in service by early 2013. The Bakken Expansion Program is expected to cost approximately US$370 million for the U.S. projects and approximately Cdn $190 million for the Canadian projects. In addition, the US$90 million Bakken Access Program, which was announced in October 2011, involves increasing gathering pipeline capacities, construction of additional storage tanks and addition of truck access facilities at multiple locations in western North Dakota and will be in service prior to the start-up of the Bakken Expansion Program.

The Berthold Rail Project includes the construction of a double-loop unit-train facility, crude oil tankage and other terminal facilities adjacent to its existing facilities near Berthold, North Dakota. The Project will have the ability to stage three unit-trains at Berthold at any given time. After an initial 10,000 bpd Phase I start-up in July 2012, the full 80,000 bpd of rail export capacity is scheduled to be in-service in early 2013.

Magnum Hunter Announces New JV Exploration Agreement with Stone Energy

Magnum Hunter Resources Corporation announced a Joint Development and Joint Operating Agreement December 12 with Stone Energy Corporation. The contract area covers an existing mineral leasehold position currently owned by both companies located in Wetzel County, West Virginia.

Terms of the new Joint Agreements include Magnum Hunter's wholly owned subsidiary, Triad Hunter, LLC ("Triad Hunter") and Stone Energy working together within the contract area on an equal and joint basis on approximately 1,925 acres with the objective of drilling nineteen (19) new horizontal wells in the Marcellus Shale over the next two years. Earlier this year, Stone Energy and Triad Hunter drilled and completed two (2) horizontal Marcellus wells, with 50% ownership interest each, on a portion of this existing mineral leasehold. It is anticipated that the additional joint effort will drill and complete the first eleven (11) wells during 2012 at an estimated capital cost of $47 million. It is estimated that the total combined capital costs associated with the contract area for the Joint Agreements will exceed $100 million. Stone Energy will be designated as operator within the contract area and each company will own a 50% working interest. In a separate agreement, Stone Energy agreed to commit its share of production from the contract area to the Eureka Hunter Pipeline System operated by Magnum Hunter's wholly owned subsidiary, Eureka Hunter Pipeline, LLC.

The additional 1,925 acre contract area is a portion of an existing 5,288 acre leasehold in which Triad Hunter will retain 100% interest in 2,979 acres. During 2011 and unrelated to the additional contract area, Triad Hunter drilled and completed three (3) horizontal Marcellus wells with a 100% ownership interest. Triad Hunter anticipates drilling an additional nine (9) wells with a 100% ownership interest on the 2,979 acres.

Magnum Hunter Resources Corporation is presently active in three of the most prolific shale resource plays in North America, namely the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale.

Kinder Morgan to Build $130 Mln Texas Condensate Processing Facility

Kinder Morgan Energy Partners announced it will build, own and operate a petroleum condensate processing facility near its Galena Park terminal on the Houston Ship Channel. With an initial throughput of 25,000 bpd and a design that provides for future expansions of up to 100,000 bpd, the approximately $130 million project will split condensate into its various components such as light and heavy naphthas, kerosene and gas oil. A major oil industry customer is underwriting, through a fee structure, the initial throughput of the facility.

“The location of our new facility, when combined with our recently announced $220 million crude/condensate pipeline, will provide customers with unparalleled connectivity to crude oil and clean products markets including refineries, chemical companies, gasoline blenders, finished product storage, outbound pipelines and marine facilities on the Texas Gulf Coast,” said KMP Products Pipelines President Tom Bannigan. The transaction is expected to be immediately accretive to cash distributable to KMP unitholders upon the project’s completion in January 2014.

The pipeline, which will transport crude/condensate from the Eagle Ford Shale in south Texas to the Houston Ship Channel, will consist of almost 70 miles of new-build construction and 113 miles of converted natural gas pipeline. Construction on the pipeline began in mid-December and Kinder Morgan expects it to be in service in the second quarter of 2012.

Crestwood Midstream to Construct $70 Mln Natural Gas Pipeline System in Marcellus Shale

Crestwood Midstream Partners announced December 13, the signing of an MoU with Mountaineer Keystone LLC, headquartered in Pittsburgh, Pennsylvania, to construct a 42-mile, 16-inch diameter natural gas gathering system to serve MK's Marcellus Shale development program in Northeast West Virginia.

The Tygart Valley Pipeline is expected to be completed by the fourth quarter 2012 and will interconnect with Columbia Gas Transmission's WB Pipeline in Randolph County, West Virginia. The TVP will provide MK and other area producers with access to the growing natural gas markets in the Washington DC and Baltimore areas. Crestwood estimates the TVP project, as currently planned, will cost approximately $70 million. Additionally, Crestwood has announced that it has hired Brian S. Blount as Vice President of Crestwood's newly formed Marcellus Commercial Region, effective December 1, 2011.

"This project is an excellent entry point for Crestwood into the Marcellus Shale which is expected to become the industry's largest shale producing region over the next few years," stated Robert G. Phillips, President and Chief Executive Officer of Crestwood's general partner. "Crestwood is pleased to announce a great long-term organic growth project in the region, the addition of Brian Blount, who has vast experience in the area, to our development team, the opening of a commercial office for the region and the expansion of our diversified portfolio of shale play midstream assets to include the fast growing Marcellus Shale."

The Tygart Valley Pipeline project will be anchored by a long term contract with MK, a First Reserve portfolio company. First Reserve, a premier private investment firm in the energy industry, also manages the fund which owns Crestwood Holdings LLC, the majority owner of Crestwood's general partner. MK will commence its horizontal drilling program in Barbour, Preston and Taylor Counties, West Virginia in mid-2012. The TVP, as currently designed, will have total capacity of approximately 200 MMcf/d, which can be expanded to approximately 300 MMcf/d with compression. MK expects to reserve firm capacity of 115 MMcf/d under a long-term, fixed-fee gathering agreement. Crestwood is currently marketing the remaining firm capacity in the project to area producers that have been accumulating Marcellus Shale leases but have been slow to commence drilling and development due to a lack of pipeline infrastructure in the area.

"We look forward to working with MK to develop this project, as well as the additional upstream gathering and other midstream services needed in the area. The MK team has a long history of success and is a very experienced Appalachian producer. Additionally, we think the TVP project will be well received by other producers in the area that have expressed the need for infrastructure to support their planned Marcellus development programs. Finally, the project also demonstrates the benefit of having First Reserve, as the sponsor of Crestwood's general partner, to bring additional value to the Partnership through its broad portfolio of energy investments," continued Phillips.

Brian Blount, a former Business Manager with Columbia Gas Transmission, has fifteen years of commercial, engineering and operations experience in the Appalachian Basin and will report to Joel D. Moxley, Senior Vice President and Chief Operating Officer of Crestwood. "We are excited to have Brian join the Crestwood team as we expand into the Marcellus Shale. Brian brings great knowledge and expertise about the Marcellus region, having worked in the region over the past decade. Brian has developed great relationships, understands the dynamics of the area and will be instrumental in Crestwood's development of the TVP," stated Moxley.

Oil States Announces New Colorado Manufacturing Facility that will Benefit Canada and the U.S.

Oil States International a diversified oilfield services company announced December 15 it has acquired a manufacturing facility north of Denver in Johnstown, Colorado that will provide additional construction capacity for both the U.S. and Canadian remote site accommodation markets.

Oil States expects that the new accommodations manufacturing facility will create 249 new U.S. jobs over the next five years. The manufacturing facility is expected to be operational commencing in the first quarter of 2012 with production starting by mid-year. Initial production capacity is projected at 2,500 modular units per year.

"The city of Johnstown is truly excited to add Oil States International as a new member of our community," stated Mark Romanowski, Mayor of Johnstown, Colorado. "We look forward to establishing a positive long term relationship and are extremely pleased to have additional job creation during these hard economic times."

Chairwoman Barbara Kirkmeyer of the Weld County Board of County Commissioners added, "We welcome Oil States International to Weld County and thank them for choosing to join our business community. This exciting project is another great example of government and business working together to achieve positive results for Johnstown, Weld County and the entire region. With the creation of more than 200 new jobs, this project fuels Weld County's stellar job growth history, which led the state in 2010 and ranked 11th highest in the country during the past 10 years."

Cindy B. Taylor, Oil States' President and Chief Executive Officer, commented, "We are pleased to invest in expansionary projects in the U.S. which will potentially create approximately 250 jobs at our new Colorado manufacturing facility. This new facility will allow us to take advantage of a highly skilled workforce in the area and will further facilitate planned capacity expansions in the U.S. shale plays and Canadian oil sands regions."

Oil States International, Inc. with recently added exposure to the mining industry through the MAC acquisition is a leading, integrated provider of remote site accommodations with prominent market positions in the Canadian oil sands and the Australian mining regions. Oil States is also a leading manufacturer of products for deepwater production facilities and subsea pipelines as well as a provider of completion-related rental tools, oil country tubular goods distribution and land drilling services to the oil and gas industry. Oil States is publicly traded on the New York Stock Exchange under the symbol OIS.

Cheniere Developing Corpus Christi LNG Project Supplied from Eagle Ford Reserves

Cheniere Energy, Inc. announced December 16 that its wholly owned subsidiary, Corpus Christi Liquefaction, LLC ("Corpus Christi Liquefaction") is developing a liquefied natural gas export terminal at one of Cheniere's existing sites that was previously permitted for a regasification terminal. The LNG export terminal site is located in San Patricio County, Texas, and it is anticipated that the terminal would be primarily supplied by reserves from the Eagle Ford Shale, located approximately sixty miles northwest of Corpus Christi. The proposed liquefaction project ("Corpus Christi Project") is being designed for up to three trains capable of producing in aggregate up to 13.5 million tonnes per annum ("mtpa").

Cheniere is launching the development of its second LNG export terminal, building upon its export capabilities in the Gulf of Mexico. Cheniere is currently developing an LNG export project at the Sabine Pass LNG terminal (the "Sabine Pass Project") through its subsidiary, Cheniere Energy Partners, L.P. The Sabine Pass Project, located in Cameron Parish, Louisiana, is anticipated to include four liquefaction trains capable of producing in the aggregate up to 18 mtpa of LNG. Cheniere has recently announced that is has entered into three long-term LNG Sale and Purchase Agreements ("SPAs") for the targeted contract quantity for three of the four trains under development and is currently in discussions with counterparties interested in entering into SPAs for the remaining capacity.

In connection with the development of the Corpus Christi Project, Cheniere has initiated the Federal Energy Regulatory Commission's ("FERC") National Environmental Policy Act ("NEPA") pre-filing review for the proposed natural gas liquefaction terminal through Corpus Christi Liquefaction. The Corpus Christi Project would be underpinned by the significant resources under development in the Eagle Ford Shale, which covers nearly 12,000 square miles in South Texas and ranks among the largest shale discoveries in the U.S. Geologic studies commissioned by Cheniere estimate recoverable oil and gas resources in the Eagle Ford Shale at over 180 trillion cubic feet equivalent, or 30 billion barrels of oil equivalent. There are approximately 200 rigs currently drilling in the Eagle Ford Shale, with increasing emphasis placed on development of the play's oil and condensate reservoir window, where significant quantities of associated natural gas rich in NGL content can be produced.

"Given the strong customer interest for capacity at the Sabine Pass Project, we have decided to initiate the development of our next liquefaction project. With our newly proposed project, we will be able to provide up to an additional 13.5 mtpa of liquefaction capacity in the Gulf of Mexico," said Charif Souki, Chairman and CEO. "We believe this is a very attractive project for global LNG buyers given its proximity to the Eagle Ford Shale, one of the most prolific shale discoveries in recent history, and look forward to discussions with interested parties."

The Corpus Christi site consists of approximately 664 acres, including 212 acres owned, 52 acres under a lease option and 400 acres of permanent easement. The site is located on the La Quinta Channel on the northeast side of Corpus Christi Bay in San Patricio County, Texas, and is approximately 15 nautical miles from the coast. Depending on feasibility and market interest, the Corpus Christi Project is expected to be constructed in phases, with each LNG train commencing operations approximately six to nine months after the previous train.

Cheniere owns and operates the Sabine Pass LNG terminal and Creole Trail pipeline in Louisiana and is pursuing related business opportunities both upstream and downstream of the Sabine Pass LNG terminal. Through its subsidiary, Cheniere Partners, Cheniere has initiated a project to add liquefaction services that would transform the Sabine Pass LNG terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG. As currently contemplated, the Sabine Pass liquefaction project would be designed and permitted for up to four LNG trains, each with a nominal production capacity of approximately 4.5 million metric tons per annum. Cheniere is also initiating the development of another liquefaction project, located in San Patricio County, Texas, that would be designed and permitted for up to three LNG trains, each with a nominal production capacity of approximately 4.5 million metric tons per annum.

Copano, Magellan Midstream Form Pipeline JV to Ship Eagle Ford Condensate to Corpus Christi

Copano Energy, L.L.C. and Magellan Midstream Partners, L.P. announced December 20 the formation of a joint venture to deliver Eagle Ford Shale condensate to Corpus Christi, Texas.

The 50/50 joint venture, known as Double Eagle Pipeline LLC, will construct and own approximately 140 miles of new pipeline to connect an existing 50-mile pipeline segment owned by Copano to Karnes, Live Oak, McMullen and LaSalle Counties of Texas, enabling delivery of condensate to Magellan's terminal in Corpus Christi. The initial capacity of the pipeline will be 100,000 barrels per day. Double Eagle also will construct a new truck unloading facility along the pipeline near Three Rivers, Texas for deliveries of condensate destined for Corpus Christi.

The joint venture project is supported by long-term customer commitments from Talisman Energy USA Inc. and Statoil Marketing and Trading (US) Inc., major producers with significant acreage in the rich gas window of the Eagle Ford Shale. The expected cost of the new joint venture facilities is approximately $150 million and will be shared equally by Copano and Magellan. Copano will oversee construction of the new pipeline and serve as operator. The companies expect to provide limited services by the end of 2012, with full service available beginning in the first quarter of 2013.

"Magellan looks forward to joining forces with Copano for this project that provides significant strategic value for both parties and our customers," said Michael Mears, Magellan's president and chief executive officer. "Combined, we are able to provide an attractive option for shippers to deliver petrochemical quality Eagle Ford condensate for use in Corpus Christi or higher-valued Texas markets via Magellan's marine capabilities."

"This project represents the next logical step in Copano's strategy of offering a full set of midstream services to Eagle Ford Shale producers and we look forward to working with Magellan on this opportunity," said R. Bruce Northcutt, Copano's president and chief executive officer. "By combining Copano's pipeline assets with access to Magellan's terminal at Corpus Christi, the joint venture will be able to leverage existing infrastructure and provide producers timely access to market alternatives at very competitive rates. The joint venture will continue to look for ways to expand the project and capture other condensate and oil-related growth opportunities in the Eagle Ford Shale play."

In connection with the joint venture, Copano will convert its existing 50-mile pipeline from natural gas to condensate service, and Magellan will make enhancements to its Corpus Christi terminal, including the construction of 500,000 barrels of new dedicated condensate storage and a new dedicated dock delivery pipeline.

For commercial inquiries about the condensate projects, please contact Rob Schaefer of Copano at (713) 737-9588, rob.schaefer@copano.com or Aaron Milford of Magellan at (918) 574-7023, aaron.milford@magellanlp.com.

Spectra, AEP, Chesapeake to Link Texas Eastern to Ohio Shale Gas Supplies

Spectra Energy Corp's Texas Eastern Transmission, LP (Texas Eastern), American Electric Power and Chesapeake Energy Marketing, Inc., a wholly owned subsidiary of Chesapeake Energy Corporation, on December 20 announced their intention to advance the development of the Ohio Pipeline Energy Network (OPEN) project, a proposed expansion of the Texas Eastern pipeline system that will connect Ohio's Utica and Marcellus shale gas supplies with the fast-growing markets attached to the Texas Eastern system, in particular natural gas-fired power generation.

The OPEN project brings together the largest producer and leaseholder in the Utica shale play, the largest power generator in the region and the premier pipeline company with over 60 years of safe and reliable operational history in the state of Ohio. The project will involve approximately 70 miles of new pipeline and create an additional 1 billion cubic feet per day (Bcf/d) of transportation capacity to serve local distribution companies, industrial users and gas-fired power generators in the Ohio market, as well as markets along the Texas Eastern system.

The project is anticipated to deliver substantial investment in energy infrastructure in the state through mineral leasing and development and construction of pipeline gathering and transportation infrastructure, as well as create significant jobs and lasting tax revenue for the state.

As part of the project, American Electric Power continues to invest in Ohio and will pursue transportation capacity that would enable the company to connect Ohio gas supplies with its gas-fired power plants in the Midwest. Chesapeake, which holds 1.5 million net acres, by far the largest acreage position in the Utica play, is pursuing capacity to access the substantial Texas Eastern markets spanning from the Gulf of Mexico to the Northeast U.S.

"We are excited about the production potential of the Utica and Marcellus shale in Ohio and the ability to serve communities with clean-burning and domestically abundant natural gas," said Bill Yardley, group vice president, Spectra Energy Transmission, Northeast. "At a time when there is growing environmental need for cleaner power generation, this new infrastructure will deliver clean, affordable and much-needed energy to Ohio, the Midwest and South."

A binding open season for the OPEN project is planned for the first quarter 2012 with the projected in-service slated for November 2014.

Canada’s NEB Ok’s $180.1 Mln Bakken Pipeline Project

In a decision issued December 22, Canada’s National Energy Board (NEB) announced its approval of the Bakken Pipeline Project Canada application submitted by Enbridge Bakken Pipeline Company Inc., on behalf of Enbridge Bakken Pipeline Limited Partnership.

The NEB determined that there is enough commercial interest to support the use of the Bakken Pipeline during its economic life. Enbridge Bakken successfully demonstrated that there will be sufficient oil supply markets for the projected production.

The Bakken Pipeline would connect to the Enbridge Pipelines Inc. (EPI) Mainline and would serve as a continuous, long-term source of supply to Eastern Canadian and U.S. Midwest markets, thus maintaining the long-term competitiveness of refineries in those regions.

In its application, Enbridge Bakken requested approval to build and operate a 123.4 kilometer pipeline and a new pump station to transport crude oil from the Bakken and the Three Forks Formations in Montana and North Dakota to refinery markets in North America. With a starting point in Steelman, Saskatchewan, the pipeline will be linked to EPI's Mainline in Cromer, Manitoba.

The NEB has also given Enbridge Bakken approval to acquire and operate Line EX-02, which is currently owned by Enbridge Pipelines (Westspur) Inc.

With an expected in service date of early 2013, the capital cost for this project is estimated to reach approximately $180.1 million.

Rex Energy Announces Receipt of Bluestone Plant Permit and Other News

Rex Energy Corporation announced that its midstream partner, Keystone Midstream, has received permit approval for construction of the Bluestone cryogenic gas processing plant in Butler County, Pennsylvania. Additionally, the company announced the closing of a senior secured second lien term loan facility and issued preliminary operational guidance for 2012.

In addition Keystone Midstream has obtained all necessary permits to begin construction of the Bluestone cryogenic gas processing plant. The plant is expected to have approximately 50 MMcf/d of gross throughput capacity and is anticipated to be commissioned during May of 2012. The company currently has an inventory of 20 gross wells in its Butler County operated area that are awaiting fracture stimulation and completion.

The company expects to begin completion of these wells throughout the first half of 2012 in anticipation of the Bluestone plant commencing operations.

Keystone Midstream has also received all necessary permits for the Voll compressor station, which the company anticipates will increase the gross throughput of the Sarsen plant, also located in Butler County, from approximately 34 MMcf/d to its full capacity of 40 MMcf/d. The company expects the Voll compressor station to be commissioned during February 2012.

Credit Facility

Rex Energy recently closed on a senior secured second lien term loan facility in an aggregate principal amount up to $100 million, with an initial commitment of $50 million. KeyBank N.A. is serving as administrative agent and Wells Fargo Bank N.A. is serving as syndication agent for the facility which matures in March 2016.

In addition to the second lien, the company's bank group has agreed to increase its borrowing base under its senior credit facility from $240 million to $255 million as a part of its semi-annual re-determination. Under the terms of the senior credit facility, the bank group re-determines the borrowing base utilizing the banks' estimates of reserves and future oil and gas prices. The current expansion of the senior credit facility is based primarily on Rex Energy's drilling results to date and production and reserves added throughout the year.

Marcellus Shale

In Butler County, where Rex Energy serves as the operator and owns a 70% working interest, the company plans to drill 12 gross (8.4 net) wells, fracture stimulate 20 gross (12.9 net) wells and place 21 gross (13.6 net) wells into service during 2012. The company expects to have 11 gross (7.7 net) wells drilled and awaiting completion in Butler County at the end of 2012.

In Westmoreland, Clearfield and Centre Counties in Pennsylvania, where Williams serves as the operator and Rex Energy owns a 40% working interest, the company is expecting to drill 17 gross (6.8 net) wells, fracture stimulate16 gross (6.4 net) wells and place 16 gross (6.4 net) wells into service during 2012. The company expects to have five gross (two net) wells drilled and awaiting completion in its non-operated areas at the end of 2012.

Utica Shale

In Carroll County, Ohio, where Rex Energy plans to serve as the operator at an approximately 80% working interest, the company is expecting to drill and place into service three gross (2.4 net) wells. During the first quarter of 2012 the company plans to place into service its Cheeseman 1H well in Butler County, Pennsylvania, which was drilled and completed in 2011. Additionally, the company expects to drill three gross (2.1 net) wells and to place into service one of these wells with two wells remaining in inventory at the end of 2012.

Illinois Basin

In the Illinois Basin, Rex Energy allocated approximately $8.4 million of its 2012 operational capital spending budget to its enhanced oil recovery projects, of which approximately $5.4 million is expected to be used for chemical injection of the Perkins Smith unit and $3.0 million for the initial phase of the Delta unit. The company has allocated approximately $2.0 million in operational capital towards production optimization projects in the surrounding conventional oil fields. In addition to its tertiary recovery and production optimization projects, the company plans to invest approximately $10.7 million in facility and health, safety and environmental upgrades.

Divestiture of Niobrara Acreage and Midstream Assets

Rex Energy's Board of Directors has authorized the company to pursue strategic alternatives regarding its DJ Basin assets, including sale or joint venture opportunities. The assets encompass all of Rex Energy's properties in the Rockies region, which include approximately 48,000 net undeveloped acres.

The company is also pursuing the divestiture of its 28% interest in midstream assets within Butler County. This would include the company's interest in the Sarsen and Bluestone cryogenic gas processing plants, and related infrastructure.

The decision to divest these non-core assets is part of the company's strategic plan to focus efforts and capital investment on Marcellus and Utica Shale exploration as well as the company's Alkali-Surfactant-Polymer project.

PA Power Plant to Convert Generators from Coal-fired to Gas

A Pennsylvania coal-fired power plant that is one of the oldest in the nation could be burning natural gas by 2015, part of a wider shift happening across the United States.

Ed Griegel, vice president of operations for the Sunbury power plant, said the move is being driven by toughening federal pollution standards and the high cost of burning coal, the Daily Item of Sunbury reported recently. Similar moves are expected from other owners of power plants that feed the wider mid-Atlantic power grid.

The plant's owner, Sunbury Generation LP, plans to close five of its six coal-fired generators and replace them with two natural gas-fired turbines.

"We'd like the new plant to be online in 2015," Griegel told the Daily Item.

The plant, which is in Shamokin Dam across the Susquehanna River from Sunbury, began operating in 1949 and can produce about 430 megawatts.

The project still needs financing and a gas pipeline will need to be built to connect to a larger interstate pipeline in the Williamsport area, Griegel said.

The federal Environmental Protection Agency will begin forcing coal-fired plants to control mercury and other toxic pollutants for the first time, leaving a choice of installing modern pollution control equipment, shutting down or converting to natural gas. In addition, the agency issued a regulation in July that requires power plants in 27 states to reduce smokestack pollution crossing state lines.

However, coal prices remain stubbornly high with demand strong from China and other developing nations, while statistics from the U.S. Energy Information Administration show natural gas futures contracts and spot prices are cheaper this winter than in any other winter in a decade.

Jennifer Kocher, a spokeswoman for the Pennsylvania Public Utility Commission, said natural gas prices are low because the sluggish economy has hurt demand and supply is surging from exploration into shale formations, including the Marcellus Shale formation.

In November, Energy Information Administration reported that power generated from coal in Pennsylvania had slid by 10 percent since 2001, while power generated from natural gas in Pennsylvania had risen eight-fold.

As of the first half of 2011, coal made up about 46% of total power generation in Pennsylvania, while natural gas generation accounted for 17 percent.

Penn Virginia Announces Eagle Ford Expansion

Penn Virginia Corporation announced December 20 that it has completed an agreement with an undisclosed major oil and gas company to jointly explore the Eagle Ford Shale in Lavaca County, Texas. The agreement establishes an area of mutual interest (AMI) between PVA, as operator, and the other company covering approximately 13,000 gross acres near PVA's existing acreage in southeastern Gonzales County. Depending on the future participation of other companies, PVA's minimum working interest in this project will be approximately 50 percent. Preliminarily, PVA estimates that a minimum of approximately 40 horizontal drilling locations may exist in the new AMI area, with the potential for additional locations assuming future down-spaced drilling.

Under the terms of the agreement, PVA will drill up to six wells by September 1, 2012 to earn its interest through the base of the Eagle Ford Shale in all of the 13,000 gross acres. PVA will carry the other company on its working interests in the first three wells.

H. Baird Whitehead, President and Chief Executive Officer stated, "We are pleased to have entered into this agreement in Lavaca County and believe the AMI acreage is highly prospective for the Eagle Ford Shale as it is situated almost adjacent to our existing Eagle Ford position in Gonzales County on which we have drilled some excellent wells. We now have a very good opportunity to increase our prospective net acreage position in the Eagle Ford to approximate our near-term goal of 25,000 net acres."

Chesapeake to Sell Gas Pipelines to Affiliate for $865 Mln

Chesapeake Energy Corp., the most active U.S. oil and natural-gas driller; agreed to sell a pipeline subsidiary to an affiliated partnership for $865 million.

Chesapeake Midstream Partners LP will buy Appalachia Midstream Services, owner of 47 percent of a 200-mile (320- kilometer) gathering system in the Marcellus Shale formation, according to a statement December 28. The system transports more than 1 billion cubic feet a day and has 15-year contracts with gas producers.

Chesapeake Energy is the largest gas producer in the Marcellus formation and holds the most acreage in the region, according to Bloomberg Industries. The formation, stretching from Canada to Kentucky, holds an estimated 84 trillion cubic feet of gas in dense shale rock, according to the U.S. Geological Survey.

Chesapeake Midstream, based in Oklahoma City, bought $500 million worth of pipelines in the Haynesville Shale in 2010 from Chesapeake Energy, which raises its ownership stake in the pipeline partnership to 46.1 percent from 42.3 with today’s sale.

The partnership, “expects to pursue a substantial number of asset dropdowns from Chesapeake in the years ahead,” Chesapeake Midstream Chief Executive Officer J. Mike Stice said in the statement.

The transaction was expected to close by December 30. Tudor, Pickering Holt & Co. acted as the financial adviser to the conflicts committee of Chesapeake Midstream’s board and Richards, Layton & Finger PA was its legal adviser.

Ecosphere Energy Services, LLC and WACCAW, LLC Sign Two-Year Water Recycling Contract Extension in Woodford Shale

Ecosphere Technologies, Inc., a diversified water engineering, technology licensing and environmental services company, has announced that its majority-owned subsidiary, Ecosphere Energy Services, LLC and WACCAW, LLC, a wholly owned subsidiary of Newfield Exploration Mid-Continent, Inc. have signed a two-year contract extension for Ecosphere Energy Services to continue providing recycling services in the Woodford Shale with its patented Ozonix technology. Ecosphere and Newfield's original contract in Oklahoma was signed in November 2008.

Robbie Cathey, Chief Executive Officer of Ecosphere Energy Services, stated, "We appreciate the opportunity to continue working with Newfield Exploration, a valued and loyal customer to Ecosphere. They are an innovative company using environmentally responsible and cost effective methods for developing their oil and gas resources.

The Ozonix Systems have proven to successfully treat flowback and produced water for bacteria and biofilms control, scale and corrosion inhibition, oil and grease removal, iron precipitation, and total suspended solids removal. Our services allow Newfield to recycle flowback and produced waters for reuse on new fracs. We look forward to continuing our service of providing quality water management solutions in the Woodford Shale."

CANADA

British Columbia First Nations Group Pledge United Front against Oil Sands Projects

A group of First Nations in British Columbia says it will "do whatever means necessary" to stop exports of crude oil from Alberta's oilsands through their territories - including the controversial Enbridge Northern Gateway oil pipeline.

The $5.5-billion project, which is being assessed by an Ottawa review panel, faces yet another public relations setback in its quest to open a new supply route to Asia.

Some 130 aboriginal groups claimed December 2 the company would be contravening international laws if the pipeline goes ahead without their approval.

One such law is the non-binding United Nations Declaration on the Rights of Aboriginal Peoples.

"We will do whatever means necessary and we do have the support," said Geraldine Thomas-Flurer, who represents the Yinka Dene Alliance of five First Nations.

"We're not afraid of Enbridge. They're making statements minimizing aboriginal people."

The First Nations issued a notice claiming a "united front" against the oilsands industry, which also includes an expansion of the Kinder Morgan Energy Partners' Trans Mountain oil pipeline. It comes one year after a similar petition called "Save the Fraser" was signed.

Aboriginals and environmentalists claim the Enbridge project is too risky and would cause irrevocable damage to the environment. If approved, the pipeline would move 525,000 barrels a day of oilsands crude 1,177 km from Edmonton to the Pacific port of Kitimat, B.C.

A spokesman for Enbridge in Calgary said First Nations opposition to the project is well-known, but said some aboriginals are on board.

"It's always of concern when people are opposed to something you're doing. We listen, we always try and learn from what people are telling us," said spokesman Paul Stanway. "The law determines that we need to get regulatory approval before we can build this pipeline. We need that permit, and that's what we're focused on."

Stanway added the pipeline is "the largest private infrastructure project in the history of British Columbia," and, once built, would add somewhere around $270 billion to Canada's GDP and provide thousands of jobs in the province. If approved, the project would start in 12 to 18 months, he said. It wouldn't be fully in service until 2017.

Travis Davies, a spokesman for the Canadian Association of Petroleum Producers, said the pipeline is the safest way to move crude oil to an expanding market.

"Access to the Asian market, which is growing very quickly, is extremely important," said Davies.

For now, the project's fate lies in the hands of regulatory bodies.

Natural Resources Minister Joe Oliver said in a statement the project is before a joint review panel - "the highest level of scrutiny possible. It is a strategic objective of this government to diversify our energy exports; however, regulatory processes will be followed before any final decision is made."

Meantime, native American tribal leaders in the U.S. planned to ask President Barack Obama on December 2 to reject a permit for the Keystone XL oil pipeline from Canada to Texas.

Quicksilver Resources and KKR Set up JV for Horn River Gas Plant

U.S. energy producer, Quicksilver Resources is teaming up with a Wall Street investment firm, KKR on a joint venture to build a new plant to process gas from emerging shale gas fields in northeastern British Columbia.

Texas-based Quicksilver Resources Inc. and investment firm Kohlberg Kravis Roberts & Co. L.P. said December 27 they will create the new joint venture with contributions from both companies.

The move is a second major step that will help Quicksilver process its shale gas from the prolific Horn River basin more cheaply and get it to markets in Canada, the United States and eventually to Asia.

The first step was TransCanada Corp.'s decision to extend its Alberta gas pipeline system to Quicksilver lands in the Horn River area north of Fort Nelson in northeastern British Columbia.

Under the deal, Quicksilver is providing its existing 32-kilometer gathering pipeline and compression equipment and 10-year contracts for gas deliveries into the partnership.

KKR is paying $125 million to Quicksilver for a 50 per cent stake in the joint venture, which will be operated by the Fort Worth, Tex. gas company.

As part of the transaction, KKR will help Quicksilver finance its portion of future development costs on the initial treating plant in return for preferential distributions to the investment firm.

Quicksilver said the treatment plant will be built at the end of the TransCanada pipeline and will help lower the cost of processing and shipping gas to market by 80 cents per thousand cubic feet of gas below other alternatives.

The companies will jointly build and operate natural gas gathering, transportation and processing infrastructure to maximize the value of the production stream from Quicksilver's development in the Horn River basin

Quicksilver said it is dedicating current and future production from its Horn River acreage to the partnership. Quicksilver has about 10 trillion cubic feet of recoverable shale gas from its Horn River properties.

"With its well-established and versatile energy business, KKR is an ideal partner in creating a low-cost and reliable solution for processing and transporting natural gas produced from the Horn River Basin for Quicksilver and other producers," said Toby Darden, Quicksilver's chairman.

"It will facilitate the sale of natural gas to multiple markets in North America and ultimately to export markets in Asia. Moreover, the partnership structure will further strengthen our financial flexibility while reducing our expected capital requirements over the next several years."

KKR partner Fred Goltz said the investment company "is excited to partner with Quicksilver to provide the capital needed to bring the substantial resources in the Horn River to market."

"We look forward to growing our commitment to this partnership over time as the company accelerates its activity in the play."

The wells in the Horn River basin are among the most prolific of shale plays in North America and could exceed more than 75 trillion cubic feet of reserves.

Quicksilver Resources is a natural gas and oil producer and explorer with a focus on unconventional deposits such as coal-bed methane, shale gas, and tight sands in North America.

The company operates across Texas, Colorado, Montana, British Columbia and Alberta. Its Canadian unit, Quicksilver Resources Canada Inc., is based in Calgary.

Founded in 1976 and led by Henry Kravis and George Roberts, KKR is a leading global investment firm with $58.7 billion in assets under management.

Shale gas now accounts for about a third of all U.S. gas output, and has lead to an economic boom in parts of Pennsylvania, the U.S. rural Midwest and Western states.

But it has also led to rising environmental concerns as well as worries about the impact of drilling trucks and rigs in small rural communities.

The controversial practice known as hydraulic fracturing or "fracking" in which sand, water and chemicals are blasted into rock deep underground to release natural gas is also being blamed for groundwater contamination.

Japex Delays Investment Decision on Canada’s Hangingstone Oil-sands Expansion

Japan Petroleum Exploration Co. said December 26 that it expects to delay by around six months its final investment decision on the Hangingstone oil sands expansion project in Alberta province, Canada.

The Japanese energy upstream company, better known as Japex, expects the delay as a result of the federal government of Canada having taken more time than originally expected to approve the project, as it has been studying very closely the safety of a planned steam line running under a major road, a Japex spokesman said.

The company previously planned to finalize its investment decision on the expansion, which targets around 35,000 barrels a day of bitumen production from around 7,000 barrels a day currently, by the end of March.

The Japex spokesman said there is no change in its plan other than the schedule, which slated the expanded production to go onstream by end-2014.

Japex holds 75% of the project as the operator, while the remaining 25% is owned by Canada's Nexen Inc.

SNC-Lavalin Wins Contract to Design 35,000 bpd MacKay Bitumen Processing Plant in Alberta

SNC-Lavalin Group Inc. has been awarded a contract to provide detailed engineering and procurement services for a central processing plant in Northern Alberta.

The MacKay River Central Plant will be designed to process 35,000 barrels per day of bitumen steam assisted gravity drainage (SAGD) production. The plant will be located approximately 40 kilometers west of Fort McMurray, Alberta. The contract was awarded by MacKay Operating Corp.

“Our SAGD team has industry-leading knowledge of oilsands technology and heavy oil recovery, as well as extensive experience on many similar SAGD projects. This award confirms our ongoing position as a SAGD service provider of choice in the oilsands market in Alberta,” SNC-Lavalin executive vice-president Andy Mackintosh stated in a release. “We are looking forward to working with MacKay Operating Corp. on this project.”

The engineering phase is underway and construction is scheduled to begin in the third quarter of 2012. The expected mechanical completion date for the construction is 2014.

Toyo-Canada Awarded EDS Contract for Alberta Oil Sands Refinery Project

Toyo Engineering Canada Ltd.*, a Canadian subsidiary of Toyo Engineering Corporation, Japan (President and CEO Yutaka Yamada) has been awarded a contract by North West Redwater Partnership (NWR) a joint venture between North West Upgrading Inc. and Canadian Natural Resources Limited to provide EDS (Engineering Design Specification) work for a heavy oil upgrading and refining complex in Sturgeon County, Alberta. This EDS work is scheduled to be completed in August, 2012.

NWR project targets to build a heavy oil upgrading and refining complex in three phases with a total capacity of 150,000 BPSD. This complex will process bitumen extracted from oil sands producing naphtha, diesel oil and other petroleum products. The project is divided into several units, and TOYO will provide engineering services for Sulfur Recovery Unit, Light Ends Recovery Unit, Sour Water Stripper Unit and Amine Treatment Unit.

Alberta has the third-largest proven crude oil reserve in the world, following Saudi Arabia and Venezuela. With this project as a beginning, TOYO is planning to continuously develop and expand its business in oil sands industry to meet the demand and requirement of this market.

* Tri Ocean Engineering Limited changed its name to Toyo Engineering Canada Ltd. in October, 2011.

Enbridge Wins Contracts to Proceed With $1.9 Bln Gulf Coast Pipeline Project

Enbridge Inc. (ENB), Canada’s largest oil pipeline company, has won enough support from shippers to proceed with a $1.9 billion project to bring more Canadian and North Dakota crude to U.S. refineries.

The Gulf Coast Access project would be a new pipeline from their terminal in Flanagan, Illinois, to Cushing, Oklahoma, in service by mid-2014, the Calgary-based company said in a statement today. The pipeline will connect with the Seaway system to carry oil to Gulf Coast facilities.

Enbridge proposed the pipeline system to handle increased production from Canada’s oil sands as well as the Bakken region in North Dakota and Montana. The line will follow rights of way for Enbridge’s existing Spearhead system.

“The Gulf Coast Access project offers near-term solutions through the cost-effective and efficient use of existing facilities and rights of way,” Stephen Wuori, Enbridge’s president of liquids pipelines, said in the statement.

The Seaway line, which is being reversed, will operate with a capacity of 150,000 barrels a day by the second quarter of 2012, Enbridge and Enterprise Products Partners LP (EPD) said in a separate statement. Pump modifications expected by early 2013 will boost that to 400,000 barrels.

GE Wants Dominant Role in Alberta's SAGD Oilsands Business

Water plays a dominant role Alberta's SAGD oilsands business, and General Electric says it intends to maintain that role in the sector with a new support center it opened recently in Fort McMurray.

"We have leadership positions in produced-water with our evaporation technology and we recycle 98 per cent of the water on some of these SAGD (steam-assisted gravity drainage) sites," said Peter Macios, GE's general manager for oilsands.

The new center will bring all of GE's different oilsands operations in the area together and will focus on business and technical support for customers.

"Our emphasis is on delivering world-class training and knowledge. The plan is for customers to send their staff to us, to bring in people during construction to train operators of the evaporators and gas turbines," Macios said.

Housing all operations under one roof should mean better co-ordination and problem-solving, he added. "If a customer approaches us and asks for help to reduce greenhouse gas emissions, with this group we can begin to tackle some of these higher-level questions."

Macios said the new center is part of GE's commitment to the provincial government for more innovation and technology development in Alberta.

"When we open our innovation center in Calgary (in spring 2012), it is going to be our global center of excellence for heavy oil. That and the Fort McMurray center are the key parts of this effort in the oilsands," he added.

While GE's business includes power systems and even a drill wellhead business, it is perhaps best known for its water and process technologies, including "zero liquid discharge" or ZLD. The technology is used around the world by industries when water use is restricted.

With the GE system, water that comes to the surface with the heated bitumen can be returned to produce more steam - unlike the common "once-through steam generators," which produce 80 per cent steam and 20 per cent salty water, which must be disposed of by downhole injection.

By producing distilled water, energy costs are cut by five per cent - it takes less natural gas to heat such pure water - while electrical bills can drop 30 per cent and chemical costs are cut in half with the latest GE system, the company says.

The Energy Resources Conservation Board is studying the issue of deep groundwater use by SAGD operators as the industry rapidly expands. Having no need to constantly add water to make up the loss in a steam system could also make it easier for some projects to win environmental approvals.

William Heins, the Seattle-based general manager for GE's thermal evaporative technology division, said recently that reliability and operating costs have improved, and the actual price of constructing and installing the units has come down sharply in the past few years.

The ZLD market was soft after the 2007 oil-price collapse, but a return to higher prices and a new focus on water use has seen the business expand.

Macios says GE now has 19 units operating in the oilsands. Working with local engineers and constructors, GE contracts the building of its units to Edmonton-area fabricators and module yards. The modules are trucked to the site as needed during the construction period.

After the oil is separated, GE's system works by concentrating the production water, removing 95 to 98 per cent of the water and leaving a dense solution.

The solidification process involves mixing a solidifying reagent with the crystallizer waste slurry to produce a solid waste that is suitable for transport and disposal in a landfill. GE's produced-water evaporator for the oilsands is part of a corporate-wide initiative designed to aggressively commercialize new technologies that will help customers meet pressing environmental challenges, the firm says.

CANADA / U.S.

Nexen-Inpex Shale Gas Deal could Lead to Kitimat LNG Expansion

Nexen has topped a difficult year by securing two significant deals related to Canadian shale gas and the U.S. deepwater Gulf of Mexico. The shale gas deal could boost prospects for a further expansion of the proposed Kitimat LNG project.

Canada's Nexen announced on November 29, 2011 that it had struck a deal to form a joint venture focused on its British Columbia shale gas business. Japanese firms Inpex and JGC have agreed to pay US$680mn (CA$700mn) for a 40% stake in Nexen's properties in the Horn River, Cordova and Liard Basins.

Nexen will retain a 60% operating interest in the assets, and the transaction is expected to close in Q112. The company added that once the JV agreement is closed, the partnership intends to proceed with appraising and developing the assets - 'depending on economic conditions'. The JV properties contain 113-424bn cubic meters (bcm) of recoverable contingent gas resources in Horn River and Cordova, with an additional 141-651bcm of prospective resources in Liard. The properties cover 1,216sq km and current shale gas output of 1.4mn cubic meters per day (Mcm/d) is expected to rise to 34Mcm/d by an unspecified future date, Inpex said.

Nexen highlighted that it would, in conjunction with its new Japanese partners, investigate the feasibility of liquefied natural gas exports. This is undoubtedly the core objective of the JV. One option is for the JV to liquefy its gas at the proposed Kitimat LNG terminal on BC's Pacific coast. The consortium behind Kitimat (led by Apache) won an LNG export license from Canada's National Energy Board (NEB) in October 2011 - to ship up to 10mn tonnes per annum (tpa). Preliminary LNG sales agreements are in place with state-run Korea Gas (2mn tpa) and Spain's Gas Natural (1.6mn tpa).

The Nexen-Inpex JV could choose to take advantage of Kitimat to monetize its own shale gas. Given that Kitimat's backers are already pushing for two 5mn tpa trains, gas from the Nexen-Inpex JV's properties could support a third train at the project, unless the JV chooses to proceed with its own rival LNG export project - a more expensive and time-consuming endeavor.

Nexen has had a difficult year. The company's Buzzard platform in the UK North Sea suffered technical problems, and subsequent repairs in the summer months led to reduced flow rates of around 80,000 barrels of oil equivalent per day (boe/d), compared with full capacity of over 200,000boe/d. Furthermore, labor unrest and broader political violence in Yemen forced Nexen to abandon its Masila (Block 14) contract. The field produced around 225,000b/d at its peak, with output net to Nexen of 24,000-28,000b/d in 2011. Nexen said on November 22 that it was 'evaluating alternatives' for its other Yemeni asset, Block 51, which produces 6,000-8,000b/d net to Nexen.

Other good news from the shale gas JV: Nexen's Toronto shares rose nearly 4.5% on November 29. This was likely to be repeated when trading commenced on November 30, the day Nexen announced a partnership with state-run China National Offshore Oil Corporation (CNC) for deepwater exploration in the U.S. Gulf of Mexico (GoM). This latter region is a key growth area for Nexen, which received a GoM drilling permit (Kakuna) in June 2011, signaling its return to GoM drilling after the Macondo oil spill. Further upside to volumes will come from the Usan project in Nigeria, which is expected to add 14,000-28,000 net boe/d upon start-up in 2012.

ARGENTINA

Canada’s Americas Petrogas Joins ExxonMobil in Argentina Shale Gas Venture

Canadian explorer Americas Petrogas has spudded a probe at a prospective shale play in Argentina’s Neuquen basin, the first of a joint campaign with ExxonMobil.

The Los Toldos Este well drilled on the Los Toldos II block is targeting the Vaca Muerta shale formation, with drilling planned to a total depth of 3250 meters.

It is the initial well of a drilling effort involving several wells across the Los Toldos acreage, covering a total of 660 square kilometers, under a farm-out agreement signed with ExxonMobil earlier this year, with Petrogas as operator.

ASIA

CHINA

Shell Reported to Have Found Shale Gas in China

Shell has found shale gas in China, marking the country’s first discovery of the resource that has transformed the U.S. energy landscape, according to a report.

An official with Shell's partner PetroChina, a unit of state-owned China National Petroleum Corporation, said drilling results from two wells drilled by Shell had been positive.

"Shell has two vertical wells and they got very good primary production," Professor Yuzhang Liu, vice president of PetroChina's Research Institute of Petroleum Exploration and Development, told Reuters on the sidelines of the World Petroleum Congress (WPC) in Doha.

"It's good news for shale gas," said Liu, who regularly represents PetroChina at industry events around the world.

China currently has no commercial shale gas production and the inaugural find could cap imports in a market that natural gas producers are hoping will drive demand.

Some industry executives doubt the explosion of shale gas in the U.S. could be replicated elsewhere due to difficult geology, the lack of water availability or land access issues.

Liu accepted the rock formations in China were "different" from those in the U.S. but denied this meant they were more challenging or less bountiful.

In less than a decade, shale gas has transformed the U.S. from gas shortage to a point where companies are planning to export liquefied natural gas, fundamentally altering the dynamics of the international gas market.

Many gas producers who were targeting the U.S. for supplies were forced to rethink their plans and China, with its booming energy demand, was seen as the answer to their need for a new market.

A Chinese “shale gale”, as the revolution was termed in the U.S., could jeopardize that market as well.

Shell declined to confirm the find but said in a statement:"Shell will complete drilling activities by the year end... as planned."

Chief executive Peter Voser has previously said he has "great expectations" for Chinese shale but was cautious in his comments to the WPC December 6.

"We are going through the exploration phase there and are exactly now analyzing what potential is available now in China," he told a news conference.

In 2009, PetroChina and Shell agreed jointly to evaluate shale gas reserves of the Fushun-Yongchuan block in the Sichuan basin.

Earlier this year, industry sources said Shell had started drilling two shale gas exploration wells in Fushun.

A U.S. Energy Information Administration report in April said China had 1275 trillion cubic feet of technically recoverable shale gas resources - by far the largest in the world - followed by the U.S. with 862 Tcf and Argentina with 774 Tcf.

EUROPE / AFRICA / MIDDLE EAST

BULGARIA

Chevron May Start Drilling for Shale Gas in Bulgaria in 2015

U.S. energy giant Chevron will start its exploratory drillings for shale gas in Bulgaria in 2015 if the country does not have moratorium in place abolishing shale gas exploration on its territory by then.

Chevron's working program foresees carrying out two exploratory drillings in 2015 and two more in 2016, Delyan Dobrev, Bulgaria's Deputy Energy and Economy Minister, has told the Bulgarian Telegraph Agency. Until then, the company will only carry out seismic research in the country, Dobrev has explained after meeting its representatives.

The Chevron representatives have also announced that the company is launching information campaigns in the regions and municipalities where the potential shale gas exploration is to take place.

On December 16, Bulgaria's Minister of Economy, Energy and Tourism Traicho Traikov revealed that the contract with Chevron for shale gas exploration and production in Bulgaria, which is still being negotiated, will not be made fully public because there is an element of a trade secret.

He gave assurances, however that talks were underway with the company for making a substantial part of the agreement available to the public.

The document would also provide for unlimited liability in the case of environmental damage and the obligation to cover 100% of the cost of eliminating it.

The issue of shale gas drilling in Bulgaria on concession by Chevron Corp escalated in the past few weeks, with environmentalists staging several protests and voicing concerns that two shale gas wells were being prepared for a launch.

Environmentalists are concerned that the potential shale gas exploration using hydraulic fracturing in Northeastern Bulgaria may cause irreversible damage to its natural state.

ESTONIA

Eesti Energia Receives Permit to Mine for Oil Shale in Estonia

Eesti Energia has received approval by the Estonian government to mine the Uus-Kiviõli mine, in Estonia.

The permit grants the company permission to mine for 208 million tonnes of oil shale, of the 362 million tonnes the company estimates are available.

The permit will be enacted in January 2014 and is valid for 25 years. Eesti Energi will be entitled to mine 4.2 million tonnes of oil shale in the Uus-Kiviõli mines annually. This amount is in addition to the 15 million tonnes the company currently mines each year.

Eesti Energia, a leader in oil shale production, currently operates two underground mines and two open pit mines.

The company's website says that construction of the mine will cost between €4 million and €5 million, and is expected to employ between 700 and 900 employees.

POLAND

Hutton Energy Awarded Two New Polish Shale Gas Concessions

Hutton Energy p.l.c. has been awarded two new concessions in Poland this month totaling 506,072 acres. Following Hutton’s farm in to ExxonMobil in August, the additional concessions raise Hutton’s net acreage in Poland to approximately 1.1 million acres, giving them one of the largest shale acreage positions in the country.

The new concessions give Hutton exposure to Carboniferous shales as well as numerous tight sands that have already been shown to contain substantial gas columns.

The Oleśnica (1,160 km²/286,642 acres) and Wieluń (887.7km2/219,430 acres) licenses, both located in southwestern Poland, have multiple unconventional play potential in Carboniferous shales and tight sands, as well as conventional targets in Permian structures. Over 150 meter thick shales with TOC values reaching 3.5% are anticipated within the concessions. Additionally thick gas filled tight sands are likely to be encountered. The play concepts will be tested in nearby licenses by oil and gas exploration company San Leon, which has three wells planned in 2011-2012.

Hutton CEO Keith Lough commented: “These blocks, along with Hutton’s existing South Prabuty block in the Baltic Basin and its 49% joint venture with ExxonMobil’s 1.1 million acres in the Podlasie Basin give Hutton an extensive, high potential portfolio in Poland. We expect to make further announcements shortly of further growth and diversification in our shale portfolio.”

Over the coming months, Hutton will be progressing its licenses through the fracking of the Siennica well with ExxonMobil, finalizing well location for the Baltic Basin concession and acquiring seismic on the new licenses.

Hutton Energy plc is the parent company of a group of subsidiary companies set up to focus on exploring and developing unconventional hydrocarbon resources in Europe, specifically targeting areas that are prospective for shale gas. Current activity spans Poland, Ukraine, Czech Republic, France, Spain and the Netherlands.

McIlvaine Company,

Northfield, IL 60093-2743

Tel: 847-784-0012; Fax: 847-784-0061;

E-mail: editor@mcilvainecompany.com