All Standard Disclaimers & Seller Rights Apply.

El Paso sells 50% in Ruby Pipeline for $700 millionCompletes Carthage expansion and TGP storage projects

El Paso Corp. is selling a 50% interest in its Ruby Pipeline project to Global InfrastructurePartners (GIP), a $5.64-billion private equity fund specializing in midstream infrastructure. Under theterms of the agreement, GIP will invest up to $700 million in the project, which represents 50% equity

interest, including reimbursing El Paso for half of the project costs incurred to date.El Paso will provide security for GIP’s investment until the completion of the

project in the form of a portionof its 55 million El Paso Pipeline Partners com-mon units and a portion of its equity in theCheyenne Plains Pipeline.

El Paso will still be responsible for con-struction and operations of the Ruby Pipeline, which is on schedule to be completed at or below itsinitial $3.0 billion budget. Should construction costs come in under budget, El Paso will retain allbenefits, but it shall also absorb any cost overruns as well. Upon completion of construction, GIPand El Paso will own the common equity of Ruby on a 50/50 basis.

Back in January, El Paso filed for a certificate of public convenience and necessity to constructthe Ruby Pipeline. In June, FERC issued a Draft Environmental Impact Statement, and El Pasoanticipates a Final Environmental Impact Statement in October.

Boardwalk beginsFayetteville Lateral repairs

Boardwalk Pipeline Partners has com-pleted remediation of pipe anomalies on its EastTexas and Southeast pipeline projects and has

received authorization tooperate these pipelines atstandard operating pressures.

The East Texas Pipeline consists of 242miles of 42-inch pipeline and originates nearDeSoto Parish in western Louisiana and proceedsto Harrisville, Mississippi. The SoutheastExpansion runs from Harrisville 111 miles, with42-inch pipe, extending to an interconnect withTransco Pipeline in Choctaw Co., Alabama.

Boardwalk reported second quarter netincome of $20.3 million, a 69% decrease from$64.7 million in the comparable 2008 period.Boardwalk’s expansion and growth capitalexpenditures were $477.5 million for the sixmonths ended June 30. Of this total, $216.4 mil-lion has been spent on the Fayetteville andGreenville laterals this year, bringing total invest-ment in the two pipelines thus far to $900 million.

Still, Boardwalk indicated that it has foundanomalies on its 1.3-BCFD Fayetteville lateraland 1.0-BCFD Greeneville Lateral – leading tointermittent downtime – which will take as longas five months to repair, beginning in September.

Boardwalk will begin by retesting the 66-mile Fayetteville header that most E&Ps use togather their Fayetteville Shale production. Theone-day test will block firm secondary or inter-ruptible deliveries to interconnects with NaturalGas Pipeline of America, Texas EasternTransmission and Mississippi River Trans missionat Bald Knob.

Delphi Midstream secures $2.0 B from American SecuritiesDelphi Midstream Partners has received an equity commitment from American Securities in

support of a strategy to invest in and acquire up to $2.0 billion of midstream energy sector compa-nies and assets. The newly-formed energy investment company includes founding partners Thomas

Karam, president & CEO, and Michael Walsh, SVP. Karam previously served as Presidentand COO of Southern Union Company (SUG), a publicly traded midstream gas com-pany. While at Southern Union, Karam completed $4.25 billion in midstream acquisi-

tions and implemented strategies incre-mentally increasing earnings by 13% annually.

Thomas Walsh was a partner and foundingmember of Highstar Capital, a family of infra-structure-focused private equity funds, whichcurrently manages over $4.7 billon investor commitments. While at Highstar, Walsh led the mid-stream energy investment strategy, including the acquisitions and sales of Southern Star Central andStagecoach Holdings.

According to its website, DMP is interested in midstream energy businesses and assets in NorthAmerica requiring a minimum equity investment of $50 million. DMP typically seeks control positions,but will also consider joint ventures or influential minority interests.

GMX sells Endeavor Pipeline to Kinder Morgan for $40 MMUses proceeds to add second Haynesville rig

GMX Resources has signed a letter of intent to sell an interest in its Endeavor Pipeline toKinder Morgan for $40 million. This transaction will provide the capital required for GMX to adda second rig to its Haynesville horizontal development program around the beginning of October.

Analysts at Tudor Pickering Holt said the move was “a big step in the rightdirection,” as the proceeds push back the company’s potential third quarter

debt covenant violation to next year’s first quarter. The analysts warned, however, that a letter ofintent “does not equal a signed deal” and thecompany’s capex is still $157 million versusonly $55 million in projected cash flow. Closingof the deal is expected within 45 days.

Endeavor Pipeline generated $2-$2.5 million EBITDA over the last 12 months, according toTPH, so Kinder Morgan must be betting on GMX growth, as the system only gathers GMX gas.The Endeavor system currently provides 80 MMCFD of takeaway capacity for GMX, which hasinvested over $70 million in the pipeline to date. The system consists of 120 miles of steel gatheringpipe, 14,000 horsepower of compression and two associated salt water disposal wells.

GMX has now drilled and completed a total of seven Haynesville horizontal wells, with twoadditional ones awaiting completion and another drilling. GMX has 62,160 (42,300 net) acresthat are prospective for Haynesville development, giving it a total of 777 (529 net) 80-acre hor-izontal locations.

August 13, 2009 • Volume 20, No. 11

MIDSTREAMNEWSServing the Midstream Marketplace with News, Insight & Opportunities

EL PAso continues on page 2

DELPhI continues on page 4

BoArDwALk continues on page 9

The Fayetteville Lateral may operate atas little as 50% of its capacity until year end.

As part of the deal GIP will reimburse El Paso for half of the pipeline costs incurred to date.

DMP is interested in midstreambusinesses and assets requiring a minimumequity investment of $50 million.

Analysts called GMX’s sale a “big step inthe right direction” towards deleveraging.

TULSA CO., OK GATHERING SYSTEMShutIn Pipeline With Equipment. 10 Sq Miles.OKLAHOMA SYSTEMSignificant CBM Exploration Within Acreage.Shallow Coal Seam Gas Production.Low Pressure-Stripper Plant-Sales Lines.100% OPERATED WI FOR SALE CBM/PIPEShutIn Pipeline: Raw Unleased AcreageSuitable To: Production & Pipeline BuyerOptimal Scenario: Buy Pipeline & DrillSELLER HAS SOLID RIGHT OF WAYS

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GMX continues on page 6

Spectra looks to raise British Columbia pipeline capacitySpectra Energy launched a binding open season for new transportation service on its

Transportation South (T-South) Zone 4 gas transmission facilities in southern British Columbia.The new service will transport gas from Spectra’s Compressor Station 2 to the Kingsgate

export point at the interconnection of the facilities of Foothills Pipe Lines (South BC)and Gas Transmission Northwest (GTN).

Two service options will be offered to prospective customers. Basic service willallow producers to transport gas on a firm service basis from the Compressor Station

2 receipt point to the Kingsgate delivery point, while “premium” service will offer rights to trans-port gas on a flexible firm basis from the Compressor Station 2 to Kingsgate and/or theHuntington delivery point.

The new services are expected to be available by November 1, 2009, and are dependent onthe company entering into an agreement with Terasen Gas for up to 87 MMCFD of firm trans-portation on Terasen’s Southern Crossing pipeline, and Terasen contracting for transportationservice on the Foothills Pipe Lines system, which runs to the Kingsgate export point.

MIDSTREAMNEWS Thursday, August 13, 2009 2

Also in June, El Paso hired a major investment bank as financial advisor for Ruby. The advisorwill recommend a package of financing options with the objective of accessing the capital marketsafter final FERC approval has been received. Assuming this approval comes in the first quarter of2010, construction would begin on Ruby Pipeline in the second quarter of 2010, targeting a March

2011 in-service date.Ruby is a 675-mile, 42-inch pipeline that will access natural gas from multiple

Rockies’ basins and move it into California, Nevada and the Pacific Northwest region.Ruby has filed with FERC to have an initial design capacity of up to 1.5 BCFD. The pipeline willrun from Opal, Wyoming, to Malin, Oregon, and then on to the California/Oregon border.

Meanwhile, El Paso Pipeline Partners has completed the acquisition of an additional 18%interest in Colorado Interstate Gas Company from El Paso Corp. for $215 million. The acquisi-tion increases the partnership’s interest in CIG to 58%, and gives El Paso Corp. additional finan-cial flexibility.

El Paso Pipeline Partners placed several expansion projects into service during the secondquarter of 2009, including the Tennessee Gas Pipeline (TGP) Carthage expansion and the ColoradoInterstate Gas (CIG) Totem Storage projects. The Carthage expansion adds 100,000 Dth/d of capac-ity from the Carthage producing area in East Texas to a new interconnect with Entergy Corp.’sPerryville Generation Station in Ouachita Parish, Louisiana.

Meanwhile, the Totem storage project involved converting a depleted gas field in AdamsCounty, Colorado, into an underground gas storage cavern. The storage field encompasses 8,040acres and has a total gas inventory of about 10.7 BCF, comprised of 7.0 BCF of working gas and3.7 BCF of base gas.

El Paso sells 50% in Ruby Pipeline continued from page 1

ProposedCompressor Station Proposed

Compressor Station

ProposedCompressor Station

MalinOpal Hub

California

Nevada

Oregon

Fremont-WinemaNational Forest

CacheNational Forest

IdahoWyoming

Utah

El Paso’s Ruby Pipeline Project

Source: El Paso Corp.

Welcome to PLS’ MidstreamNews, a tri-weekly report on

gathering, purchases, pipelines, mergers, acqui-sitions, capital and performances in the mid-stream marketplace. In addition to the news, thereport also carries select listings of property (PP),override (RR) and midstream (G) assets for sale,along with lands (L) and prospects (DV).

Anonymous listings are coded alpha-numerically.Clients interested in accessing only listing-package information call (or email) PLS andprovide the listing codes.

Besides the MidstreamNews, PLS publishes amonthly recap of the e&p market in theProspects & Properties and a&d market recapsin the A&D Transactions.

Additional product details can be obtained byvisiting our website at www.plsx.com.

MIDSTREAMNEWS

PLS, Inc.P.O. Box 4987, Houston, TX 77210Phone: (713) 650-1212Fax: (713) 658-1922Website: www.plsx.com

Managing Director of ResearchBrian Lidsky - blidsky@plsx.com

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M. Lynn Bass, GasRock Capital, LLC

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Frank Pottow, Greenhill Capital

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To obtain additional information on properties forsale in this MidstreamNews, please contact our listingdept: (713) 650-1212 or by fax: (713) 658-1922 with theproperty number. Please note only clients are able to re-ceive additional information.

The MidstreamNews newsletter is published every three(3) weeks by PLS, Inc.

© Copyright 2009 by PLS, Inc.Federal copyright law prohibits unauthorized reproduction by any means and imposes fines up to$100,000 for violations.

How To Use

Thursday, August 13, 2009 MIDSTREAMNEWS3

Enbridge teams with Chevron for deepwater infrastructureEnbridge Inc. agreed with Chevron to possibly expand its central Gulf of Mexico offshore

pipeline system. Under the terms of the LOI, Enbridge proposes to construct, own and operate theWalker Ridge Gathering System (WRGS) to service Shell’s potential Jack, St. Malo and Big Foot

ultra deepwater developments. The estimated cost of WRGS is $500 million.WRGS is expected to include 190 miles of 8-inch,10-inch and/or 12-

inch diameter pipeline at depths of up to 7,000 feet and will have a capac-ity of 100 MMCFD. Enbridge’s offshore pipelines currently transport 40% of all deepwater gas pro-duction in the Gulf, accounting for a total of 2.5 BCFD.

In June, Enbridge agreed with Imperial Oil Resources and ExxonMobil to transportblended bitumen from the Kearl project in the Athabasca Oil Sands region of northern Alberta tothe Edmonton area. The first phase of thenew pipeline system is a 140-kilometre

pipeline from Kearl Lake toEnbridge’s Cheecham Terminal.

Meanwhile, Enbridge and Enbridge Energy Partners concluded a joint funding agree-ment under which Enbridge will effectively fund two-thirds of the $1.2-billion U.S. segment of theAlberta Clipper crude oil pipeline project.

Under the terms of the agreement, Enbridge will participate in the debt financing that EEPraises for the project, and will fund two-thirds of the project’s equity requirements directly intoEnbridge Energy LP (EELP), the subsidiary of EEP which is constructing the project. Enbridge willbe entitled to two-thirds of the earnings and cash flow which EELP generates from the base project.

“In addition to Alberta Clipper, EEP is undertaking a number of growth opportunities includ-ing the expansion of our North Dakota system to accommodate increased Bakken shale produc-tion, the recently completed Southern Access expansion of our crude oil mainline, and the Claritygas pipeline,” said Terrance McGill, president of the partnership’s management company and ofits general partner.

The deal should also help shippers, as it should result in lower tolls by reducing EEP’s cost tofinance the debt component of Alberta Clipper.

The Alberta Clipper project consists of a 36-inch diameter pipeline from Hardisty, Alberta, toSuperior, Wisconsin. The segment from Hardisty to the U.S. border is being undertaken by EnbridgePipelines at an estimated cost of $2.0 billion; the segment from the U.S. border to Superior is beingundertaken by EEP through EELP. Both segments are scheduled to be in service by mid-2010. Theinitial capacity of the line will be 450,000 BPD of heavy crude, expandable to 800,000 BPD

Source: Enbridge, Inc.

Midstream News

Enbridge is also constructing a pipeline tocarry 800,000 BoPD from Alberta to wisconsin.

Denbury considers $1.0 billion CO2 pipeline

Denbury Resources has initiated a feasi-bility study of a possible long-term CO2

pipeline project which would connect pro-posed gasification plants in theMidwest to the company’s exist-ing CO2 pipeline infrastructure

in Mississippi or Louisiana.The study will determine the pipeline

route, construction costs, and regulatoryrequirements. Denbury hopes to complete thestudy by the fourth quarter of this year, follow-ing which the company will make a final deci-sion on whether to proceed with the pipeline

Meanwhile, the two proposed Midwesterngasification plants with which Denbury hasCO2 purchase contracts, one in Illinois and onein Indiana, have been selected to proceed to theterm sheet negotiation phase under the U.S.Department of Energy Loan Guarantee Pro -gram. The program is designed to spur techno-logical innovation in the industry.

This feasibility study will investigatemultiple pipeline routes connecting the numer-ous proposed gasification sites within the area.Denbury’s preliminary internal estimates sug-gest this would include a 500- to 700-milepipeline system with a preliminary cost esti-mate of $1.0 billion. The potential pipelineproject would likely take from four to fiveyears to complete.

Moreover, a third proposed gasificationplant in Mississippi with which Denbury has aCO2 purchase contract was also selected by theloan guarantee program. Denbury is evaluatingwhether to construct a 110-mile pipeline toconnect the plant to the existing Free StatePipeline that runs along the Gulf Coast.

“That multiple proposed gasificationplants have been selected for the next phase ofthe government loan guarantee program facili-tates our stated goal of augmenting our naturalCO2 with man-made volumes,” Denbury CEOPhil Rykhoek said.

“We see our ability to sequester man-madeCO2 to be very timely in view of our govern-ment’s goal to reduce CO2 emissions and esti-mate that our current enhanced oil recoveryprojects store between 25% and 50% more CO2

than will be emitted from the incrementalrecovered oil.”

Denbury is looking for new sources ofCo2 in order to facilitate its tertiary floods.

Enbridge’s Alberta Clipper Pipeline

Fort McMurray

Edmonton

Hardisty

Kerrobert

Existing Enbridge pipelinesAlberta Clipper crude oil pipeline

Regina

CromerGretna

Clearbrook

Superior

FIVE STATESENERGY CAPITAL, LLC

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214.560.2571www.fivestates.com

For more information: capitalinfo@fivestates.com

MIDSTREAMNEWS Thursday, August 13, 2009 4

Williams holds two Transco open seasonsWilliams is holding a non-binding open season for its Transco pipeline to obtain shipper com-

mitments for an expansion designed to provide up to 150,000 Dth/d of firm transportation serviceto markets in Virginia, Washington and Maryland.

The Mid-Atlantic Connector Expansion project will provide service from aninterconnection with East Tennessee Natural Gas in Rockingham Co., NorthCarolina, to delivery points as far north as Transco’s interconnect with Columbia Gas

Transmission in Montgomery Co., Maryland. The proposed in-service date for the expansion isNovember 2012.

Separately, Williams is holding a non-bindingopen season for an expansion project to provideincreased capacity on its Transco to serve markets inthe southeastern U.S. The proposed Mid-Southexpansion project will allow shippers to subscribe to incremental year-round firm transportationservice on Transco’s mainline from its Station 85 pool in Choctaw Co., Alabama, to an intercon-nection with Cardinal Pipeline Company in North Carolina.

“By the end of this year, Transco customers will have access to as much as an additional 3.0 BCFD at Station 85,” said Phil Wright, president of Williams’ gas pipeline business.

The Mid-South expansion project is designed to provide up to 230,000 Dth/d of new capacity;it is anticipated to be available as early as September 2012. The level of market interest will deter-mine the cost and pipeline facilities required for the expansion.

Columbian pipeline nearing completion for 170,000 BOPDCanada’s Pacific Rubiales Energy (35%) and Columbia’s Ecopetrol (65%) are constructing

an oil pipeline that links the Rubiales field with the Monterrey station in Columbia. This projectwill enable the companies to substantially reduce the transportation costs for Rubiales crude to the

export port of Covenas, while ensuring that there will be adequate throughput capacity tobring the Rubiales field to its full production potential.

The 200-mile, 24-inch pipeline has been under construction since 2008. Line fillingwill start during August 2009. The initial capacity of the pipeline will be 170,000 BOPD, upgrad-able to 260,000 BOPD.

The Rubiales and Piriri oil fields are in Columbia’s Llanos Basin. Pacific Rubiales has net pro-duction of 34,000 BOEPD from the area, with working interests in 34 blocks in Colombia and Peru.

EOG promises gas volumes for Kitimat LNG facilityEOG Resources will provide natural gas to support Kitimat LNG’s proposed export terminal in

Kitimat, British Columbia. The two companies are still negotiating a definitive agreement underwhich EOG would supply specific quantities of the LNG facility’s 700 MMCFD gas feedstock.

Kitimat President Rosemary Boulton said the facility presents a compelling opportunityfor producers to leverage growing gas reserves in Western Canada, notably the emergingHorn River and Montney Shale plays, and sell into new international markets, such as Asia.

EOG is the first producer to sign an MOU with Kitimat LNG, although Kitimat has also signedMOUs with leading LNG companies such as KoreaGas Corporation and Gas Natural for the purchase ofLNG produced at the terminal.

Kitimat LNG is in ongoing discussions withpotential terminal users, LNGbuyers and other natural gas producers for the five million tonnes per annumproject. It is thought that a pipeline may be necessary to carry gas produced inBritish Columbia to the Kitimat facility.

However, Kinder Morgan Canada President Ian Anderson has said a con-necting pipeline may be some way off. “The key question when you think aboutAsia is when will producers develop the markets for Canadian oil and gas in anadequate volume that would support and underpin a major pipeline expansionfor the West Coast?,” Anderson said. (For more news on Kitimat and Canada’s

emerging shale plays see PLS Three-Part Study analyzing Canada’s emerging shale plays from July2009.)

“By the end of this year, Transcocustomers will have access to as much as an additional 3.0 BCFD.”

The facility may access newly-discovered shale gas and export it tomarkets in Asia.

Kitimat LNG answers a Mayday call from Canada’s gas producersKitimat LNG was a long-shot when it Prst surfaced almost Pve years ago with

plans for a 600 MMCFPD import terminal at the northern British Columbia port ofKitimat. Those chances became even more remote as the challenge ofPnding suppliers triggered a series of postponements, despite success bythe pro ponents in rounding up the necessary regulatory approvals.

Then, a year ago, all bets were oOwhen privately-held Kitimat LNG did atotal about-face, switching from an LNGimport to an export project. Previousdreams of shipping LNG from Canada toAsia had run aground. Producers weresimply unwilling to make commitmentswhen they had easy, apparently unlimitedaccess to U.S. markets.

But Kitimat LNG president RosemaryBoulton made what was then a shaky andis now a virtually unassailable argumentthat Canada needs the leverage of alternative markets to counter therapid deterioration of exports to the U.S.,triggered by development of shaledeposits in the U.S. and British Columbia,the prospect of cargoes of excess LNG

from Australia, Saudi Arabia and Qatar heading for North American shores and theintroduction of the Rockies Express pipeline, delivering 1.5 BCFPD from the U.S.Rockies to the Midwest and Ohio. And Kitimat LNG suddenly stands as a possibleanswer to an otherwise dismal outlook for Canada’s gas producers.

Unable to compete against new U.S.pipelines, which are cutting into key out-lets in the Midwest and California, andunable to match the production and transport costs from the Barnett and Haynes villeshales, Canada is facing the unthinkable.

Just at a time when forecasters such as Cambridge Energy Research Associatesare forecasting that Canada has the potential to raise production by 4 BCFPD to 19.8 BCFPD over the next four years, the door to the Lower 48 states is closing.

Enter Kitimat LNG, with its plan to start exporting 700 MMCFPD in 2013 with Asia and possibly Latin America andEurope, as its primary objectives.

Some may have thought Boultonwas living on Cloud Nine last year when she said the “growing econ omies of thePaciPc Rim and the rapidly increasing demand for LNG make Asia a natural market for British Columbia’s plentiful and expanding supplies of gas.”

She hammered home the argument that the deepwater port at Kitimat, in northern B.C., is close to Asian markets, while an extensive pipeline network already con-nects B.C. gas suppliers to the Kitimat area. And she stuck with her message that Canadianproducers could pay a heavy price for relying exclusively on the U.S. for their exports.Combine that with delays and cancellations of several LNG liquefaction terminals alongwith the demand for clean-burning gas and Kitimat LNG started to make sense.

That once-wobbly case has found its feet this year with a series of MOUs – twowith potential major customers and, most crucially, one with a supplier. For openers,Kitimat LNG reached agreement with Korea Gas (the world’s single largest LNGimporter) and Spain’s Gas Natural to take 40% and 30%, respectively, of its capacity.

Canada’s oilpatch seesparadigm shift

Canada’s oil and gas industry maybe approaching a paradigm shift, whichPLS has analyzed in three successiveMarketAlerts. This shift has resulted Prstfrom the actions of the provincial gov-

ernments,whose diOer-ing royaltyframeworks

are causing industry to jettison Albertain favor of British Columbia.

Back in 2008, with oil at $140/bbl,Alberta’s government looked to increaseits share of the windfall by raising royaltyrates; but the move – which unwittinglycoincided with the worldwide economicdecline – had the opposite eOect of driving many E&Ps into neighboringBritish Columbia, which was only toohappy to abide.

Last year, B.C. laid the groundworkthrough a package of royalty and infra-structure incentives that set oO recordlease sales of $2.6 billion. The province isalso giving producers a break by delayingroyalty payments until capital costs arepaid oO, as well as moving forward with a program that could pay up to 50% ofinfrastructure costs.

The government has been aided bythe emerging Horn River and MontneyShale plays, which EnCana Pgures tohold 800 TCF of OGIP. CONTINUES on page 4

CONTINUES on page 3

Tuesday, July 21, 2009 • Volume 20, No. 11

CANADIAN EXPLORERA Review of Exploration, Lands & Prospect Activity in the Canadian E&P Sector

MARKETALERT

1. Kitimat LNG is a game changer forCanada Gas

2. EOG signs on to supply gas for LNG3. Fast pace provides realistic target to construction start-up in 2Q 2010.4. ExxonMobil, Imperial, Taqa Northjoin rush to Horn River.

5. PLS provides research conclusionsto this three part series.

QuickLook

Special Series - 3 of 3BC Northern Shales

Canada on cusp of boosting output by 4 BCFPD just as door to Lower 48 is closing.

Canadian dreams of gas price competitionmay be becoming reality shortly.

RESEARCH CONCLUSIONS

Top Horn River Players

Source: PLS, Inc. Research

CCoommppaannyy AAccrreess

EnCana 260,000

Exxon 250,000

Apache 220,000

EOG 157,000

Quicksilver 127,000

Devon 100,000

Nexen 88,000

Taqa North 31,500

www.plsx.com

DMP seeks interests in businesses andassets with existing operations, predictablerevenue models and the ability to proactivelymanage exposure to price volatility in the

underlying commodities. The partner-ship will also consider late-stagedevelopment and growth capital

projects are “exceptional opportunitiesand fit with our strategy.”

“We believe that successful businesses inthe midstream energy sector are built throughpartnerships with management teams and witha long-term view of value creation,” Karamsaid in a statement.

DMP’s equity backer, American Secur -ities, is a New York-based private equity firmthat invests in market-leading companies inNorth America with annual revenues generallyranging from $100 million to $1.0 billion. Thefirm’s investments are funded from more than$6.0 billion of committed capital.

AS traces its roots to the family officefounded in 1947 by William Rosenwald toinvest and manage his share of his family'sSears, Roebuck & Co. fortune. AS is currentlyinvesting its $2.3 billion fifth fund which has a25-year horizon

AS is led by Matt LeBaron Scott Wolf.LeBaron is managing director and heads thepower & energy industry and works in theindustrial and consumer industries as well. Withthe firm for nearly a decade, he has also man-aged or worked on American Securities' effortswith previous portfolio companies includingCambridge International, Miltex InstrumentCompany, Primary Energy and VUTEk.

Wolff joined American Securities in 2002and is a vice president at the firm. Previouslywith Merrill Lynch, Wolff worked in theMergers & Acquisitions Group, focusing on avariety of industries including consumer prod-ucts, food, packaging and automotive

Delphi Midstream cont. from page 1

Asset-Backed Midstream Company OfferingEngineering, Operating & Financial Resources

Phone: 303-991-1480 • Fax: 303-451-7394

www.StonehengeEnergy.com

Why wait for the capital you need? If you are a small- tomid-sized operator with a project in the $1- to $20 million

range, contact Patriot Exploration at 713-353-3997patriotexploration.com

Inergy looks to increase Marcellus takeaway capacityInergy Midstream LLC is conducting two non-binding open seasons. The first is for the

MARC I Hub Line Project, and the second is for the North-South Project. Together, these projectswould allow shippers to wheel gas bi-directionally on a firm basis to and from the Millennium

Pipeline in Tioga Co., New York, approximately 75 miles to and from Transco’s LeidyLine near its compressor station 517, and to and from all points in between.

The MARC I Hub Line Project seeks to gauge interest for Northeast shippers thatdesire to move gas bi-directionally between the South Lateral of Inergy’s Stagecoach Gas StorageFacility, TGP 300 Line near its compressor station 319, and Transco’s Leidy Line near its com-pressor station 517.

The Marc I Hub Line Project includes 43 miles of lateral piping, compression, and intercon-nect facilities connecting the Stagecoach SouthLateral to Transco. The Marc I Hub Line Project,when placed in-service, will allow Inergy to wheelvolumes to and from Stagecoach’s South Lateral,TGP, Transco, and the Millennium Pipeline.

In addition, The North-South Project seeks to gauge interest for shippers that desire to wheelgas on a firm basis through Inergy’s existing North and/or South Laterals of Stagecoach to and fromTGP’s 300 Line, Inergy’s proposed MARC I Hub Line, and the Millennium Pipeline.

The North-South Project includes setting additional compression and expanded measurementfacilities at Inergy’s existing Millennium and TGP interconnects. The proposed projects are target-ing Northeast shippers seeking: (i) additional market supply flexibility and reliability; (ii) access toadditional gas supplies in the market area; (iii) liquid points of sale for locally produced gas fromthe Marcellus Shale and Trenton-Black River plays, among others; (iv) additional storage opportu-nities; and (v) capture of pricing differentials between the various interconnected market pipelines.The anticipated in service date for both pipelines is September 2011.

Thursday, August 13, 2009 MIDSTREAMNEWS5

The new pipelines will connect thestagecoach storage facility with theTransco Pipeline.

Inergy’s Marc Hub Line

Millennium offers increased New England pipeline capacityMillennium Pipeline Company launched a non-binding open season for firm shippers seek-

ing unsubscribed firm, forward haul transportation capacity commencing November 1, 2009. Millennium Pipeline can directly or indirectly serve gas markets in New York, New Jersey and

New England. Western New York gas storage and production can be accesseddirectly through Millennium, and Canadian gas can be delivered through inter-connections with Empire State Pipeline. Millennium serves markets along its

route in the Southern Tier and lower Hudson Valley, and it serves New York City through an inter-connect at Ramapo.

Millennium Pipeline is anchored by its customers National Grid, Con Ed of New York, CentralHudson Gas and Electric Corporation and Columbia Gas Transmission. Millennium’s design willallow it to transport up to 525,400 Dth/d, based on market needs. Millennium is jointly owned byNiSource, National Grid and DTE Energy.

North Lateral

Leidy Hub

PA

PANJ

MA

CT

NY

South Lateral

MAR

C I H

UB

STAG

ECOA

CH

STAG

ECOA

CHMAR

C I H

UB

Marcellus ShaleFormation

Sempra opens Cameron LNG terminal in Louisiana

Sempra has begun commercial operationsat its Cameron LNG receipt terminal near LakeCharles, Louisiana. Over the past month, start-

up and commissioning activities havebeen completed, including the arrivalof the facility’s first two LNG com-missioning cargoes.

“Our LNG business now has two fully oper-ational North American receipt terminals to servesuppliers in both the Atlantic and Pacific mar-kets,” said Chairman Donald Felsinger.

Sempra owns 100% of the Cameron LNGfacility and has sold 40% of its processingcapacity to Italy’s Eni under a 20-year terminal

services agreement. Last month, Sempra LNGsigned a flexible agreement to purchase up to 50cargoes from one of the world’s largest suppli-ers of LNG, Ras Laffan LNG, an affiliate ofRasGas Company. The agreement allows car-goes to begin August 1, 2009, and runs throughDecember 31, 2010. Each cargo could containup to 4.8 BCF.

Cameron LNG’s first cargo arrived June 21aboard BP’s British Diamond, which brought LNGfrom Trinidad. A second ship, BP’s BritishEmerald, arrived at the terminal June 30. Cameronis capable of processing 1.5 BCFD of LNG.

Sempra’s other LNG receipt terminal,Energia Costa Azul, is located in BajaCalifornia, Mexico, and commenced opera-tions in May 2008. Energia Costa Azul is thefirst LNG receipt terminal on the West Coast ofNorth America and is capable of processing 1.0 BCFD. Both these receipt terminals storeLNG, return it to its gaseous state and dispatchit into pipelines for customer use.

Cameron is capable of processing 1.5 BCFD of LNG.

Source: Inergy Midstream, Inc.

Due Diligence &Document TransferCall (713) 650-1212 today to discusspotential opportunities.

Gas spot prices rebound throughout the U.S.Natural gas spot prices posted robust gains in the last 3 trading days of the report week ending

Wednesday, August 5, failing to react to a decreased cooling load in some areas of the country,according to information released by the Energy Information Administration, an arm of theDepartment of Energy.

Gas prices posted increases at both the spot and futures markets since last Wednesday, withprice increases at the spot market ranging between 12 and 43 cents per million Btu(MMBtu). During the report week, the price at the Henry Hub spot market rose to$3.61 per MMBtu, increasing by 20 cents or 5.9 percent.

Areas in the South, including the East and West South Central CensusDivisions, which generally rely heavily on gas-powered electricity generation, saw robust cooling

load during the week, undoubtedly lendingsupport to the spot prices.

Since Wednesday, July 29, natural gasspot prices increased at each of the 78 marketlocations analyzed by the EIA, with increases

ranging between 12 and 43 cents per MMBtu or 4 and 13%. Natural gas prices in Florida recordedthe highest weekly increase of 42 cents per MMBtu, followed by the 37-cent jump in the West Texasand Midcontinent regions. Trading regions along the Gulf of Mexico coast (Louisiana, East andSouth Texas, and Alabama/Mississippi) rose between 18 and 35 cents per MMBtu. In addition towarm temperatures that supported price increases in East and South Texas, the explosion on theEnterprise Product Partners’ High Island 264 platform in the Gulf of Mexico likely caused somedisturbance in the market.

While temperatures were relatively moderate in the Northeast, prices still rose since lastWednesday, registering the smallest weekly increase in the lower 48 States. On the week, prices inthe Northeast increased by an average of 19 cents or 5% per MMBtu to a regional average price

MIDSTREAMNEWS Thursday, August 13, 2009 6

Pricing Data

support for the futures contract priceincreases came from rising crude prices andthe possibility of more gas shut-ins on the way.

Regional Spot Prices for Natural Gas

Estimated Average Wellhead Price

of $3.92. Despite registering the smallestweekly increase, the average price in theNortheast remains the highest in the lower 48States. As of August 4, all of the other tradingregions (with the exception of the FloridaCitygate price) recorded average pricesbetween $3.39 (Rocky Mountains) and $3.73(Arizona/ Nevada) per MMBtu.

At the New York Mercantile Exchange(NYMEX), the natural gas futures contract forSeptember delivery increased by 49 cents to$4.042 per MMBtu. The September futures con-tract closed above $4.00 per MMBtu for the firsttime since June 19 on Monday, reaching $4.031per MMBtu. The near-month contract hasremained above $4.00 per MMBtu since August 3.

Contract prices for delivery in October andduring the upcoming heating season months(November-March) registered even highergains, recording price jumps of between 51 and57 cents per MMBtu. The 12-month futuresstrip, which is the average price of contracts fordelivery over the next year, rose $0.505 perMMBtu or 10% to $5.063. Despite this week’sincrease in prices, however, natural gas futuresprices remain at relatively low levels and areabout 50% lower than last year at this time.

The five wells with lateral lengths inexcess of 4,000 ft. have averaged 5.4 MMCFDfor the first 30 days of production after IP rates

around 9.0 MMCFD. Fourof those five wells have been

on stream for at least 60 days with an average of3.9 MMCFD for the second 30-day period andtwo of those five wells have been on productionfor at least 90 days and have averaged 3.4MMCFD for the third 30-day period.

Total company production of 3.31 BCFe inQ2, was up 2% from a year ago and up 3%sequentially. GMX reported a net loss of $8.2million for the second quarter, on a $41.9 mil-lion capex program, a decrease in expendituresof 41% from the first quarter. GMX said itwould decrease 2H spending 60% from 1H, toan estimated $45 million.

This budget will supply one operated riguntil October, when the second will be addedwith proceeds from the pipeline divestment.GMX has lowered its full year production guid-ance ~5% to 14.0 BCFe after terminating ordelaying three other rig contracts at a cost of$6.0 million. In order to increase liquidity, thecompany said it is exploring ways to monetizeseveral additional non-core assets.

GMX sells pipeline continued from page 1Spot Prices Thu Fri Mon Tue Wed($ per MMBtu) 30-Jul 31-Jul 3-Aug 4-Aug 5-Aug

Henry Hub 3.34 3.34 3.43 3.53 3.61

New York 3.70 3.57 3.76 3.99 4.04

Chicago 3.30 3.28 3.44 3.60 3.73

Cal. Comp. Avg.* 3.29 3.27 3.43 3.56 3.71

Future ($ per MMBtu)

September Delivery 3.743 3.653 4.031 4.001 4.042

October Delivery 3.988 3.909 4.285 4.275 4.328

*Avg, of NGI’s reported average for: Malin, PG&E citygate and Southern California Border.Source: NGI’s Daily Gas Price Index (http://www.intelligencepress.com)

Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09

Price ($ per Mcf) 4.16 3.72 3.43 3.45 3.45 3.43

Price ($ per MMBtu) 4.04 3.62 3.33 3.35 3.35 3.33

Note: Prices were converted from $ per Mcf to $ per MMBtu using an average heat content of 1,029 Btu per cubic foot as published in Table A4 of the Annual Energy Review 2006. Source: Energy Information Administration, Office of Oil and Gas.

NGP Capital Resources Company

www.ngpcrc.com

Thursday, August 13, 2009 MIDSTREAMNEWS7

Western Gas buys Rockies plant from Anadarko for $107 MMWestern Gas Partners LP is acquiring certain midstream assets in the Uintah Basin in north-

eastern Utah from Anadarko Petroleum for $107 million. Western Gas said the acquisition is partof its strategy to grow by “regularly acquiring assets from Anadarko,” which spun off Western Gas

into an MLP back in 2008 to operate its midstream assets in East andWest Texas, the Rockies and the Midcontinent.

The latest acquisition is comprised of a 51% membership interest in the Chipeta gas pro-cessing complex, which includes two recently completed processing trains: a refrigeration unitcompleted in November 2007 with a design capacity of 240 MMCFD and a 250-MMCFD cryo-genic unit which was commissioned in April 2009. Chipeta provides processing services toAnadarko and third-party production in the Greater Natural Buttes field and has currentthroughput of 375 MMCFD. Following the closing of the acquisition, Anadarko will retain a24% membership interest in Chipeta.

The acquisition will be financed primarily with debt, through the issuance of a three-year,$101.5-million, 7% note to Anadarko, as well as through the issuance of 351,424 common units toAnadarko and 7,172 general partner units to Western Gas Holdings, LLC, the partnership’s generalpartner, at an implied price of $14.89 per unit. Following the transaction, the partnership will con-tinue to have substantial additional borrowing capacity, including $100 million of availability underAnadarko’s $1.3-billion committed credit facility.

NGAS sells half of Appalachian gathering system for $28 MMNGAS Resources closed the sale of a 50% undivided interest in 485 miles of Appalachian gas

gathering facilities to Tulsa-based Seminole Gas Company for $28 million. The gas gathering sys-tem spans parts of southeastern Kentucky, eastern Tennessee and western Virginia, and intercon-

nects with Spectra’s East Tennessee Interstate pipeline network. NGAS applied all of thesale proceeds to reduce its credit facility to $52 million.

As part of the transaction, Seminole also has a six-month option to purchase NGAS’remaining 50% in the gathering system for $22 million. Under certain conditions, NGAS may requireSeminole to exercise its purchase option, which would allow NGAS to further reduce bank debt.

NGAS will remain as operator of the gathering system and the company retained firm capacity of30 MMCFD on the network, ensuring its Appalachian gas production has access to the interstatepipeline network long term.

The gathering system delivers gas to the Rogersville processing plant, which is jointly owned bySeminole and NGAS, and which discharges gas into the East Tennessee network.

Seminole and Murphy Energy recently completed construction of an NGL storage and rail ter-minal near the Rogersville processing plant. The terminal allows NGLs to be dispatched to markets viarail car, resulting in lower costs and higher net backs to producers.

Since 2007, Seminole has acquired a producer services book of business, constructed a processingplant, a nitrogen rejection plant, and a rail terminal in Appalachia in addition to this gathering system.

A&DBP and Irving Oil will not be moving

forward at this time with the proposed secondrefinery in Saint John, New Brunswick,as a result of global economic andindustry conditions.

Buckeye Partners LP reported secondquarter net income of $52.1 million, up from$40.9 million for the second quarter of 2008.

Yet Buckeye also recorded an assetimpairment charge of $100 million,leading to an actual net loss of $48.4

million for Q2 2009. Vol ume declines in pipelineand termin alling and storage businesses largelyoffset the benefits of increased tariffs and feesand new terminals added since the secondquarter of 2008.

Jacobs Engineering Group received acontract from Indian Oil Corporation to provideproject management services for a delayed cokerunit at its Paradip refinery in the State of Orissa.The contract is estimated at $350 million.

CB&I was awarded a $530-million contractby Abu Dhabi Gas Industries (GASCO) to six low temperature/cryogenic storage tanks, twoambient storage tanks and the associated piping,

controls, power distribution and civilworks systems. The project is part ofthe expansion of GASCO’s Inte grated

Gas Development project in Abu Dhabi. CB&Irecently completed four cryogenic tanks forGASCO at the same site.

Millennium Pipeline Co. hired two newsen ior executives to its organization: StanBrownell as VP, Marketing and Business Develop -ment, and John Keith as VP, Finance and Con troller. Brownwell was most recently head ofMarket Development and Trading for HarkenEnergy. Keith was formerly the acting controllerof New York State Electric and Gas Corporation.

North American Energy Resources isacquiring 20% in the Washington GatheringSystem, which serves all the natural gas pro -duction in the company’s area of interest inWashing ton Co., Oklahoma.

Briefs

NGAS

Tesoro’s narrowing margins lead to net loss of $45 MMU.S. refiner Tesoro Corporation reported a second quarter net loss of $45 million, compared

to net earnings of $4.0 million a year ago. Second quarter operating income was $11 million versus$74 million in the second quarter of 2008. The variance was primarily due to lower gross margins

and decreased throughput, partially offset by lower operating costs.The company’s realized gross margin of $8.52/bbl decreased by $1.58/bbl from

a year ago. Tesoro reduced the amount of distillate it produced as West Coast distillatemargins decreased by more than $22/bbl from a year ago. During the second quarter, discountsfor spot California heavy crudes were down45%, as San Joaquin Valley Heavy traded$8/bbl below Alaska North Slope (ANS)versus a discount of $15/bbl a year ago.Discounts for South American heavy crudes also weakened as Oriente crude traded $7/bbl belowANS versus $13/bbl a year ago. These heavy crudes represent almost 70% of Tesoro’s crude slatein the California region.

Total system throughput for the second quarter was 565,000 BPD, down 7% from the 2008second quarter as a result of a full plant turnaround at Alaska, and planned maintenance atGolden Eagle. Additionally, Tesoro said it is monitoring throughput and inventory levels tomeet lower demand.

Second quarter capital expenditures were $173 million, including turnaround spending. Thecompany said it now expects to spend less than its announced capital budget of $600 million dol-lars for the full year.

Tesoro now expects capital spending tocome in below its $600 million annual budget.

Comprehensive Services

for Independent Oil and Gas Producers

Expect more for your energy.

713.209.1112cimaenergy.com

Midstream AssetsPLS can put its experience, marketing and publishing resources to work to sell your midstream assets. For more information on how PLS can help you sell your assets call(713) 650-1212 or access www.plsx.com

MIDSTREAMNEWS Thursday, August 13, 2009 8

Targa drops down downstream business to its partnershipTarga Resources Partners LP is acquiring Targa Resources’ downstream NGL business

for $530 million. The downstream business includes the logistics assets, NGL distribution andmarketing and wholesale marketing segments. As part of the transaction, Targa will provide dis-

tribution support to the partnership beginning in Q2 2009 and continuing through thefourth quarter of 2011.

Consideration to Targa will include $400 million in cash and $130 million innewly issued units of the partnership, the maximum equity component permitted under Targa’sfinancing agreements.

The acquisition improves business diversity and adds primarily fee-based cash flow to thepartnership. The acquisition consists of NGL infrastructure including three fractionation facilitieswith 380,000 BPD gross capacity; storage wells with 65,000 BPD of capacity and 15 terminalfacilities; 800 miles of pipeline, storage and ter-minalling; and the second largest LPG importand export facility in the Gulf Coast.

For the full year ending December 31,2009, the downstream business is expected togenerate adjusted EBITDA of $80 to $85 million. Maintenance capital expenditures associatedwith the acquisition will be $10 million and $5 million for the 12- and four-month period endingDecember 31, 2009, respectively.

Targa Resources Partners already owns an extensive network of integrated gatheringpipelines, seven gas processing plants and two fractionators throughout Southwest Louisiana, thePermian Basin and the Barnett Shale.

The partnership is paying $500 millionfor assets including the second-largest LPGterminal on the Gulf Coast.

MIDSTEAMMARKETING

Group

Questar Pipeline – sub of Questar Corp.that provides interstate gas transportation andstorage services – saw net income increase 18% in

the second quarter of 2009 to$15 million. For the first half of

the year, Questar Pipeline’s net income was $29.7million compared to $28.6 million in the year-agoperiod. The increase was due to one-time losses inthe 2008 results. Operating expenses in the firsthalf of 2009 fell to $0.09 per Dth transported,down from $0.10 in the year earlier period, the netresult of a 7% increase in transportation volumesand a 6% decrease in expenses.

Shell agreed for Technip and Samsungto design and install multiple floating LNG facili-ties to serve Shell’s various offshore projects over a

period of up to fifteen years. Shell andTechnip-Samsung also signed a con tractfor execution of the front end engineer-

ing and design (FEED) for Shell’s 3.5 million tonneper annum (mtpa) FLNG solution.

TransCanada Corp. appointed Russ Girlingas COO. Girling has been with TransCanada for the last 15 years, most recently as leader of thePipeline business.

U.S. refiner Valero Energy reported a netloss of $254 million for the second quarter of2009, compared to net income of $734 million in

the year ago quarter. For the first sixmonths of the year, net income of $55

million compared to net income of $995 millionfor the first six months of 2008. Valero alsoreported a second quarter 2009 operating lossof $317 million, a sharp turnaround from operat-ing income of $1.2 billion in the second quarterof 2008, due mainly to lower diesel and jet fuelmargins and lower sour crude differentials. Forexample, the company said benchmark GulfCoast ultra-low-sulfur diesel margins versus WTIcrude decreased 79% from $28.85/bbl in Q22008 to $6.16/bbl in Q2 2009.

Velocity Midstream Partners LLC (Velocity)finalized its acquisition of Berry Petroleum’smidstream infrastructure in Harrison and Lime -stone Co., Texas. Velocity will provide Berry, andother pro ducers near the systems, with high andlow pressure gathering services. In addition to theacquisition of the systems serving the CottonValley production, Velocity has com mitted to buildout in both Harrison and Lime stone Countyconcurrent with Berry’s Haynesville horizontaldrilling plans.

Whiting Petroleum expects its 17-mile oilline connecting the Sanish field to the Enbridgepipeline in Stanley, North Dakota, to be in service

in the fourth quarter. The 8-inch line willhave a capacity of 65,000 BOPD. Enbridgeplans to expand its oil pipeline in

Mountrail Co., North Dakota, to a capacity of161,000 BOPD from its current capacity of 110,000BOPD. This expansion is expected to becompleted in the first quarter of 2010.

Briefs

Enterprise benefits from increased NGL demandEnterprise Products Partners reported second quarter net income of $187 million, versus

$263 million for the second quarter of 2008. Net income included a $34 million charge in connec-tion with Enterprise’s dissociation from the offshore TOPS project in April as well as a $4.0 million

charge related to the pending merger of Enterprise and TEPPCO.The partnership generated $328 million of distributable cash flow in the second quar-

ter, down slightly from $347 million in the same quarter of 2008. “Volumes handled by our integrated midstream system were at record or near record levels for

the quarter,” said CEO Michael Creel. “Despite lower drilling activity, our 36,000-miles ofpipelines transported a record 9.7 trillion Btu/d and 2.2 MMBPD of liquids.” Creel said the com-pany benefited from higher demand for NGLs by the petrochemical industry.

Enterprise also benefited from an increase in volumes and cash flow from its IndependenceHub and Trail pipeline system and platform, which together accounted for a $44 million increasein gross operating margin (totaling $56 million) compared to the same quarter of last year whenthe system was out of service for 66 days due to repairs.

In addition, record equity NGL pipeline volumes of 1.8 MMBPD and strong results from theRockies gas processing plants and NGL marketing activities resulted in a $36 million increase ingross operating margin compared to the secondquarter of last year.

Onshore, gas pipeline volumes increased12% to a record 8.3 TBtu/d for the quarter, ver-sus 7.4 TBtu/d for the same quarter of 2008. Thelargest volume gains were on the White River Hub, Piceance and Jonah systems. The White RiverHub began operations in December 2008.

Enterprise also completed the 1.1-BCFD Sherman Extension of its Texas Intrastate system inlate February; however, it was in limited service throughout the second quarter due to pipelineintegrity issues on the connecting take-away pipeline, Boardwalk Pipeline Partners’ Gulf CrossingPipeline, which has since been repaired (see related story on cover page).

Total capital spending in the second quarter was $273 million. Through the second quarter,Enterprise incurred outlays for 65% of its expected organic growth capital budget for 2009. Totalrevenue for the second quarter decreased almost 50% to $3.5 billion, down from $6.3 billion in thesame quarter of 2008 due to lower commodity prices.

second quarter revenues of $3.5 billionwere down nearly 50% from $6.3 billion ayear ago.

(337) 234-1125

www.ilandman.com

Thursday, August 13, 2009 MIDSTREAMNEWS9

Current Natural Gas Stocks by RegionEstimated Percent

Current One-Week Implied Net Prior 5-Year DifferenceStocks Prior Stocks Change from (2004-2008) From a 5 Year

All Volumes in BcF 7/31/09 7/24/09 Last Week Average Average

East Region 1,579 1,523 56 1,433 10.2

West Region 442 441 1 364 21.4

Producing Region 1,068 1,059 9 796 34.2

Total Lower 48 3,089 3,023 66 2,593 19.1

Working Gas in storage rises to all time highAs of Friday, July 31, working gas in underground storage rose to 3,089 BCF, with inventories

exceeding the 5-year (2004-2008) average by about 19%, according to the EIA. Working gas stocksin storage as of the end of July 2009 were at an all-time high, exceeding the previousrecord of 2,896 established at the end of July 2007.

Natural gas in storage is now 580 BCF or 23.1% higher than year-ago levelsand 496 BCF or 19.1% higher than the 5-year (2004-2008) average. The current levelof natural gas in storage is even higher than any end-of-August working stocks since 1976, the EIAreported. If net injections through the end of the refill season (August to October) match the 5-year(2004-2008) average of 781 BCF, stocks entering the next heating season will be more than 300 BCF above the previous all-time high of 3,565 BCF, set at the end of October 2007. The latestnet injection of 66 BCF exceeded the 5-year average net injection of 48 BCF by about 38% and lastyear’s net injection of 57 BCF by about 16%.

The relatively large additions to storage resulted from robust volumes of natural gas producedand strong economic incentives, according to the EIA. The National Weather Service’s degree-daydata indicates that close-to-normal temperatures prevailed for the United States as a whole for theweek ended August 5. The average U.S. temperature was 75.4 degrees, one-tenth of a degree higherthan normal. However, some of the Census Divisions, particularly New England, Mountain, andPacific, recorded temperatures that were significantly warmer than normal, deviating between 13%and 57% above normal. With the increase in natural gas futures prices during the most recent week,producers have a significant incentive to continue to inject natural gas into storage for use duringthe heating season. The price of the heating season strip as of yesterday was $5.756 per MMBtu,|54 cents higher than a week ago.

Total production in the Fayetteville averaged 1.3 BCFD as of last April, with SouthwesternEnergy approaching 1.0 BCFD in the play. SWN has secured 2.4 BCFD of pipeline capacity in

the play to accommodate an expected ramp up in volumes over the next severalyears. The company has contracted for 800 MMCFD with Boardwalk, another

400 MMCFD with Centerpoint/Ozark and 1.2 BCFD on the Fayetteville Express Pipeline.The 2.0 BCFD Fayetteville Express Pipeline, however, is not expected to go into service until

late 2010 or early 2011. The 187-mile pipeline, owned by Kinder Morgan and Energy TransferPartners, will provide more outlets for gas and gets Fayettevillegas east of the Haynesville Shale.

For now, Southwestern is trying to transfer to other systems 400 MMCFD of its total 800 MMCFD in volumes currently committed to Boardwalk. Phase I of the Fayetteville Lateral(from Conway to Cleburne County) was placed in service last December. In April, Boardwalkplaced both the Fayetteville and Greenville laterals in-service, before announcing the need forremediation work in July.

Analysts at Tudor Pickering Holt said the repairs could temporarily limit Fayetteville growthwhile also increasing transportation costs. Currently, the Fayetteville lateral is on-line and transport-ing 550 MMCFD of its 800 MMCFD capacity.

The analysts added, however, that they are not expecting meaningful impacts unless (1) avail-able capacity falls significantly below 550 MMCFD or (2) timing or repairs is latter end of one tofive month estimate. The repair process assumes Boardwalk will shut down sections of theFayetteville lateral, which will take volumes to zero intermittently.

Boardwalk begins Fayetteville Lateral repairs continued from page 1

Source: Energy Information Administration: Form EIA-912, “Weekly Underground Natural Gas StorageReport,” and the Historical Weekly Storage Estimates Database. Row and column sums may not equaltotals due to independent rounding.

Prospects & PropertiesThe latest news articles online:

Chevron to cease all land base drilling inU.S. for natural gas

Granite Wash play proves worth for Chesapeake and Newfield

Southwestern reaches 1.0 BCFD in theFayetteville

Encore plans Bell Creek field CO2 flood

McMoRan continues deep gas exploration

Penn Virginia drills two Haynesville horizontals

EnCana raises initial flow rates in Haynesville

EXCO, BG target 34 Haynesville horizontalwells this year

Forest drills 20 MMCFD Haynesville well

Goodrich continues Haynesville success

Range raises Marcellus EURs

CNX brings eighth Marcellus horizontal online

Cabot ramps up Marcellus Shale production

Brigham’s rampant in the Bakken with 2,000 BOEPD well

Gasco updates Riverbend project in Uinta Basin

EOR continues CO2 flood at Milnesand

Double Eagle completes Catalina wells

Noble’s raises resource potential to 6.3 TCFat Tamar discovery

Anadarko hits discovery with deepwaterVito well

Denbury lowers production guidance

Saxon continues completion activity

July 15, 2009 • Volume 20, No. 6

PLS, Inc., P.O. Box 4987Houston, TX 77210

PROSPECTS & PROPERTIESA current compilation of prospects, properties, overrides for sale and promotional insight.

–e&p

Chevron turns deepwater Frade <eld on streamChairman O’Reilly predicts demand recovery

Chevron Corp. has begun crude production from the Frade field, the com-pany’s first operated deepwater development in Brazil. The $3.0-billion proj-ect, with continuing development drilling, is expected to achieve peak

production of 90,000 BOEPD in 2011.Chevron has 51.74% operating interest in the Frade field,

which contains an estimated 200 to 300 MMBO of recoverableoil. The field is situated in the Campos Basin in 3,700 feet of

water, 230 miles northeast of Rio de Janeiro. Frade is a subsea developmentwith wells tied back to a floating production, storage and offloading vessel.Crude oil production is planned to be exported to world markets, and gas pro-duction is expected to be provided fordomestic use in Brazil.Other partners in the project are

Petrobras (30%) and Frade JapãoPetróleo, a joint-venture company of INPEX, Sojitz and JOGMEC (18.26%).Elsewhere, Chevron confirmed another discovery within the Moho-

Bilondo license in the Republic of the Congo. The Moho Nord Marine-4 well,in which Chevron holds 31.5% WI, is 46 miles offshore in 3,537 feet of water.Moho Nord Marine-4 was drilled to 13,907 feet TD and proved a 535 foot

(163 meter) column of high-quality oil flowing at 8,100 BOPD. The discoveryfollows two previous successful exploration wells, Moho Nord Marine-1 and2, drilled in the permit area in 2007, and the positive appraisal well MohoNord Marine-3 in 2008.The permit area's deepwater Moho-Bilondo project, which began produc-

tion April 2008, consists of subsea well clusters that flow into a floating pro-cessing unit. Maximum production of 90,000 BOPD is expected in 2010.Chevron's partners on the permit area are Société Nationale des Pétroles

du Congo (15%) and Total (operator and 53.5%).

Photo courtesy of Larry Lee Photography - www.larrylee.com

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Featured Listings

Apache’s North Sea well =ows 10,500 BOPDDrills another 8,000 BOPD well in Egypt

Apache Corp. brought its Forties Charlie 6-3 well in the North Sea onproduction at a rate of 10,500 BOPD. The well is the seventh developmentwell brought on production at Forties in 2009, and its initial production rate

is the field's highest since 1994."The well helped confirm the potential for similar

stranded oil accumulations in close proximity to the Char-lie platform," said Rod Eichler, Apache's co-COO and international president."Three similar targets are among Apache's current inventory of 79 drillingtargets at Forties."An eighth well - the Forties Alpha

2-5 - recently logged 115 feet of payand is being completed.Since acquiring Forties in 2003, Apache has invested over $1.2 billion to-

wards infrastructure-related projects that have significantly improved thefield's operating efficiency and process system reliability. At the time of theacquisition, Forties was producing about 40,000 BOPD. Currently, the fieldis producing more than 70,000 BOPD.Apache owns 97.14% interest in Forties, which is the largest single oil ac-

cumulation discovered and is currently the second-highest producing field inthe United Kingdom sector of the North Sea.The field produced 60,940 BOEPD net to Apache in the first quarter of

2009, which was actually down 2% from the fourth quarter of 2008 due toplanned downtime. Last quarter, Apache brought online three new wells,which added average production of 4,870 BOEPD during the first quarter.The FA4-5 well started production in January and was still flowing more than5,000 BOEPD three months later.The company said targets at Forties are generated through 4-D (time-lapse)

seismic and AVO-inversion techniques which monitor fluid saturation and move-ment within the reservoir. Currently, Apache has 60 targets in the field ranging insize from less than 0.5 MMBOE to 1.5 MMBOE.

PLS discusses Pyrenees & Winter discoveriesWith New<eld Exploration VP John Jasek

Newfield Exploration has assembled a number of exploration prospectsin the deepwater Gulf of Mexico over the last several years. Since the begin-ning of 2008, the company has drilled seven successes out of eight exploration

attempts in the deepwater Gulf.Most recently, Newfield reported

two new deepwater GOM discoveries,known as Pyrenees and Winter. ThePyrenees discovery, which sits in 2,100 ft. of water in GardenBanks Block 293, encountered 125 ft. of net pay in three inter-vals. The well has been temporarily abandoned as the partnersconsider field development plans. Delineation drilling is

planned for the second half of 2009. Newfield operates the development (40%WI) with partners Stone Energy (15% WI), Ridgewood Energy (15%), Arena Ex-ploration (15%) and Deep Gulf Energy (15%). Speaking exclusively to PLS, Newfield’s Exploration VP for the Gulf of

Mexico, John Jasek, said the company’s success is due to its high quality re-gional seismic datasets. “These allow us to identify the

best remaining prospects. We usethese regional datasets along with ourexperienced exploration staff to com-pare our prospects to analogs in existing discoveries,” Jasek said.Meanwhile, the Winter discovery, located in 3,400 ft. of water in Garden Banks

Block 605, encountered 44 ft. of net pay in two sands. This well also was tem-porarily abandoned to consider development options. Newfield is operator with30% WI with partners Apache (25%), Deep Gulf (25%) and Royal Offshore (20%).“Both the Winter and Pyrenees prospects were internally generated and

acquired through lease sale in 2008,” Jasek added. Predrill estimates for thetwo projects were 200 BCFe each.

Frade is expected to achieve peakproduction of 90,000 BOEPD in 2011.

Apache averaged 60,000 BOEPDfrom its Forties 3eld last quarter.

New3eld has spent $10.8 MM neton these two discoveries thus far, outof a total gross cost of $88 MM.

Pioneer Natural Resources hascompleted its first horizontal well inthe Eagle Ford Shale play in SouthTexas. The Friedrichs Gas Unit #1, inDewitt Co., had an initial flowrate of 3.7 MMCFeD, including2.7 MMCFD and 160 BOPDafter partially completing onlyfive stages of a planned eight-stagecompletion.Mechanical problems in the origi-

nal lateral required a sidetrack with amodified well path significantly reduc-ing the well’s exposure to the mainreservoir section. Pioneer estimatesthat only two stages of the frac, repre-senting less than 500 feet of the 3,000-foot lateral, penetrated the shale andare contributing to gas production.

CEO Scott Sheffield said thecompany has drilled more than 150vertical wells through the Eagle FordShale, where it has 310,000 grossacres. But Pioneer is now changingits focus to horizontal drilling.“We will drill a second Eagle

Ford horizontal well more than 40miles southwest of the first locationin the third quarter. We then plan todrill additional wells to high grade

our acreage, including anotherwell in the Friedrichs area,”Sheffield added.Pioneer has a 2009 capital

budget of $250 to $300 million, withonly 10% devoted to South Texas thisyear. But the company is devoting thelargest chunk of its spending, or35%, to its Oooguruk project on theNorth Slope of Alaska, where recentresults have been more encouraging. Currently, operations are under-

way to drill four horizontal laterals inthe Nuiqsut formation during thesecond and third quarters. Two ofthese laterals will be fracture-stimu-lated producing wells and two will bewater injection wells.The first water injection well was

completed and is being produced tem-porarily to measure the unstimulatedproductive capability of the Nuiqsutformation. It was tested at an initialrate of 2,500 BOPD and has been puton production at a stabilized rate of1,000 BOPD.

Pioneer has already drilled over150 vertical Eagle Ford Shale wells.

Late last year GMX Resourceswas an exclusive driller of verticalCotton Valley wells. Now, the com-pany is using its East Texas experienceto help develop the Hay-nesville Shale play under-lying its 42,000 net acres.The effort has led to thebest wells in GMX’s history.Most recently, GMX completed the

Blocker Ware 19H Haynesville hori-zontal well with a 4,446-ft. lateral and

12-stage frac. The well posted an initial24-hour production rate of 8.9MMCFD. The company then com-pleted the Blocker Heirs 12H well witha 4,934-foot lateral and 14-stage frac,posting an IP rate of 9.4 MMCFD.In fact, GMX’s last five horizon-

tal Haynesville wells have averaged

IP rates greater than 8.9 MMCFD,and the first three such wells with lat-eral lines greater than 4,000 feet havecollectively averaged more than 5.8

MMCFD in the first 30-day period.The company is cut-

ting drilling costs in theplay as well by reducing drillingtimes and improving frac techniques.Since the start of 2009, per well costshave fallen from $9.5 million downto $7.5 million, as GMX has reducedspud-to-sales drilling times from 100days to 75 days. By year end, GMXexpects drilling costs to fall furtherdown to $5.5 million with only 50days elapsing from spud to sales.Since transforming itself in No-

vember 2008, GMX has alreadycompleted eight Haynesville hori-zontals and it has a total of 12 suchwell completions planned for 2009,targeting 65 BCFe of proved devel-oped reserves.

Since the start of 2009,Haynesville well costs have fallenfrom $9.5 million down to $7.5 MM.

Venoco raises ‘09production guidancePlans 70 wells inSacramento Basin

Venoco, Inc. has raised its annualproduction guidance 6.6% from its pre-vious estimate to 20,250 BOEPD,

while at the same time re-ducing its operating expenseguidance 10% from its pre-vious estimate to 13.50/boe.

As a comparison, LOE was $19/boe inthe fourth quarter of 2008.The company’s 2009 capex re-

mains the same at $150 million, butits liquidity has increased since clos-ing the $201-million sale of its Hast-ings Complex to Denbury Resourcesback in February. Denbury plans towaterflood the field in the first halfof 2010, and Venoco will retain 23%WI after payout, which could even-tually yield between 15 and 30MMBO net to Venoco.

Immediately to the west of Hast-ings is the Manvel field, which Venococalls a “Hastings look alike” as it con-tains the same Frio Sands. The com-pany said it will leverage its experienceat Hastings and hopes to conduct CO2floods on the field next year.But 54% of Venoco’s 2009 capex

budget is allocated to the SacramentoBasin, where the company plans todrill 70 gross development wells andundertake more than 150 workoversthis year. Venoco is currently runningthree rigs in the play, where it is pro-ducing 10,208 BOEPD on its200,000 net acres in the Basin. Since2005, Venoco has drilled more than300 wells in the Sacramento Basin.The company is also cutting costs by25% in the area this year.

Venoco calls the Manvel 3eld a“Hastings look-alike” on whichwater4ooding could begin next year.

Pioneer drills <rst Eagle Ford horizontalLatest North Slope well better than expected

GMX continues Haynesville transformationLatest shale wells exceed 9.0 MMCFD each

NEWFIELD continues on page 7

APACHE continues on page 14

CHEVRON continues on page 9

VENOCO continues on page 3

PIONEER continues on page 11

GMX continues on page 9

For more information, contactRichard Martin at713-650-1212

Search & Seek– Access our online libraryfor past and/or present publications.

Not a client? Call 713-650-1212.

E&P

MIDSTREAMNEWS Thursday, August 13, 2009 10

NYMEX Natural Gas Futures Near - Month Contract Settlement Price, WTX Intermediate Crude Oil Spot Price & Henry Hub Natural Gas Spot Price

NYMEX Closing Dates

NYMEX Natural Gas Settlement PriceWTI Spot PriceHenry Hub Spot Price

$12

$8

$4

$0

3/30

/09

4/6/09

4/13

/09

4/20

/09

4/27

/09

5/4/09

5/11

/09

5/18

/09

5/25

/09

6/1/09

6/8/09

6/15

/09

6/22

/09

6/29

/09

7/6/09

7/13

/09

7/20

/09

7/27

/09

8/3/09

Note: The West Texas Intermediate (WIT) crude oil price, in dollars per barrel, is converted to $/MMBtu using a conversion factor of 5.80 MMbtu per barrel. The dates marked by vertical lines are the NYMEX near-month contract settlement dates.

Source: Natural gas prices, NGI’s Daily Gas Price Index (http://intelligencepress.com), WTI price, Reuters News Service (http://www.reuters.com)

4 / 28 / 09 5 /27 / 09 6 /26 / 09 7 / 29 / 09

Dol

lars

per

Mill

ion

Btu

Conoco sees midstream, downstream earnings fallConocoPhillips’ midstream segment generated second-quarter earnings of $31 million, com-

pared with $162 million in the second quarter of 2008, primarily due to lower realized prices anddecreased throughput volumes. Midstream earnings for the first six months were $154 million,

compared with earnings of $299 million in the corresponding period of2008. The decrease came despite a first-quarter $88-million after-taxgain on shares issued by a subsidiary of Conoco-sub DCP Midstream.

Conoco’s refining and marketing (R&M) segment was hit hardest by the economic downtown,reporting a second-quarter loss of $52 million compared with earnings of $664 million in Q2 2008.The quarter included an after-tax impairment of $72 million related to the sale of the company’sstake in the Keystone Pipeline to partner TransCanada.

The domestic refining crude capacity utilization rate for the second quarter was 93%, com-pared with 94% in the second quarter of 2008. The international crude oil capacity utilization ratewas 72%, down from 88% in the second quarter of 2008, reflecting turnaround activity in Europe,and run reductions at the Wilhelmshaven, Germany, refinery due to market impacts.

Worldwide, R&M’s refining crude oil capacity utilization rate was 88%, down from 93% inthe second quarter of 2008. Before-tax turnaround costs were $121 million in the second quarter,down from $170 million a year ago.

PVR buys Oklahoma gasplant from Atlas for $23 MM

Atlas Pipeline Partners LP is selling theSweetwater II gas processing facility for $22.6million in cash. The purchaser, Penn VirginiaResource Partners, will provide gas to the

facility and will make reimbursementfor its proportionate share of plantoperating expenses. Atlas will con-

tinue to operate the Sweetwater complex, whichincludes additional processing facilities.

Penn Virginia funded the acquisition withborrowings under its revolving credit facility. Theacquired assets consist of a 60-MMCFD process-ing plant within Atlas’ 180-MMCFD Sweetwaterfacility in Beckham Co., Oklahoma.

PVR Midstream expects the facility to beprocessing PVR’s gas by the end of August aftersystem connections and field compression areinstalled at an additional cost of $5.0 million.

Additionally, a recently completed 40-MMCFDprocessing plant expansion in PVR’s Beaver/Spearman complex (known as the PanhandleSystem) is expected to be in service in August

These projects will increase PVRMidstream’s processing capacity in thePanhandle System to 260 MMCFD and overallprocessing capacity to 400 MMCFD. Theincreased capacity will allow PVR to process anadditional 50 MMCFD which was beingbypassed due to capacity constraints in thePanhandle System and will alleviate pipelinepressure-related volume constraints in the east-ern portion of the Panhandle System.

In addition, Atlas will gather gas for PennVirginia and transport it to the Sweetwater IIfacility. Atlas said the facility was “redundant”and was superseded by the new Nine Mile pro-cessing facility completed earlier this year andalso in western Oklahoma. The proceeds fromthe transaction will be used to reduce outstand-ing borrowings.

These projects will increase PVr’sprocessing capacity in the Panhandlesystem to 260 MMCFD.

Magellan closes Longhorn Pipeline purchase for $350 MM Magellan Midstream Partners said its purchase of substantially all of the assets of Longhorn

Partners Pipeline has been approved by the bankruptcy court. The 700-mile common carrierpipeline system transports refined petroleum products from Houston to El Paso.

A terminal in El Paso, comprised of a 5-bay truck loading rack and over 900,000barrels of storage, is included in the purchase. This terminal serves local petroleum prod-ucts demand and distributes product to connecting third-party pipelines for ultimatedelivery to markets in Arizona, New Mexico and, in the future, Northern Mexico.

The purchase price for the pipeline system is $250 million plus the fair market value ofline fill, which is currently estimated at $100 million. Management intends to finance theacquisition with debt.

Magellan will connect this pipeline to its existing terminal at East Houston to provide addi-tional supply options for customers to transport petroleum products to Southwestern markets.Further, Magellan is constructing an additional 400,000 barrels of storage at the El Paso terminal.Both projects should be complete by mid-2010 at an estimated cost of $25 million.

2.8

www.phdwin.com

TRC Consultants, LC now offers the complete solution for evaluating, managing, and reporting reserves and performance data

NOW EVEN MORE POWERFUL WITH

Increase Deal Flow and Business Opportunities. Call PLS at (713) 650-1212 to subscribe or access www.plsx.com for more information.

Thursday, August 13, 2009 MIDSTREAMNEWS11

TEXASEAST TEXAS GATHERING SYSTEM8-Mile Gas Pipeline.MARSHALL/HARRISON AREANear Penn Virginia Well.MultiPay East Texas Reservoirs.Cotton Valley, Travis Peak.Haynesville Development Possible.Pipeline Capacity: 10,000 MCFDMultiple Line Right-Of-Way. PIPELINEHigh Pressure Line.Interconnects w/ Two Main ETX Lines.SUBJECT TO PRIOR SALECONTACT SELLER FOR MORE INFO

G 1425PL

LAMPASAS CO., TX PIPELINE12.5-Miles Pipeline Project Needed.COPPERAS COVEExcavation Has Begun.Completion Expected In 90 Days.SEEKING PROJECT PARTICIPANTS100% WI Possible For Pipeline.Active w/ New Production. PROJECTNeeds Max Capacity: 12 MMCFDPotential Cash Flow: $270,000/MnProved Reserves In Area.COME SEE US AT NAPE-BOOTH 2054

G 6389PL

REEVES CO., TX ROYALTY FOR SALE168-Royalty Acres.Strategically Located In Prolific Area.Two Units Established, 1 Well Drilling.Woodford And Barnett Shale Targets. ROYALTYPayZone Consists Of 800 Ft. Of Shale.Abundant Pipeline Access.TWO LARGE CAP OPERATORS

RR 2083

SOUTHEAST TEXAS LEASE~16,500-Net Mineral Acres.GULF COAST COAL BASINTo Top Of Midway. 2,300-5,800 Ft. LEASE5 Ft. - 22 Ft. Cumulative Coal.Mineral Rights For Lease.

DV 9845L

WESTERN ELLIS CO., TX MINERALS654-Acre Tract.BARNETT SHALE TRENDMinerals For Sale, Fully Abstracted3-Proposed Wells. 6-Total Well Potential.Within 5 Mi Good Range Barnett Production.Pipeline In Place. 30-Acre Lake For Frac.ACREAGE COST = MARKET DISCOUNT80% Undivided Minerals For Sale.Remaining 20% Also Likely. BARNETTOffsetting Wells EUR: 1.8-3.3 BCFAvg EUR In Area: 2.88 BCFAvg Net PV10 Value: $3,800,000Engineering & Logs Available.CALL SELLER FOR MORE DETAILS

M 2397

LOUISIANAN. LOUISIANA HAYNESVILLE PROJECT3-Completing. 2,081-Net Acres (80% HBP)— 39 Horizontal Locations IdentifiedSENTELL FIELDHaynesville Shale Formation (11,500 Ft.)— Cotton Valley Upside.~40% OPERATED WI; ~30% NRI HAYNESVILLE— Additional WI Potentially Available.Net Proved Reserves: 12 MBO & 3.9 BCFTotal Net Reserves: 191 MBO & 63.5 BCFTotal Net PV10 Value: $98,706,450— Ran on NYMEX STRIP (July ‘09)Pipeline Infrastructure in Place3RD PARTY TECHNICAL FIRMHOUSTON DATA ROOM SHOWING

DV 4285PP

MIDCONTINENTANTRIM CO., MI DEVELOPMENT6-Wells Drilled. 2-Producing.ANTRIM SHALE6,500-Net Acres. ANTRIM SHALEAdditional 34-Well Program (24 Months).160 Acres Per Well Density.Lachine-Norwood Zones: ~100 Ft. ThickHORIZONTAL (HIGH-ANGLE) DRILLING45% NonOperated WI; 78% NRI (Lease)Current Gross Production: 400 MCFDGas Pipelines Are In Place.Recoverable Proved Rsrvs: ~10.28 BCFRecoverable Probable Rsrvs: ~12.19 BCFRecoverable P+P Rsrvs: ~22.47 BCFTotal Project AFE: ~$26,280,000OPERATOR HAS ADDITIONAL DATA

DV 2450PP

FRANKLIN CO., AR PROJECT350-Potential Wells. 24,000-Contiguous Ac.FAYETTEVILLE SHALEObj 1: Fayetteville ShaleObj 2: Chattanooga Shale & Weddington.Areas of Vertical & Horizontal Drilling.4-Wells Ready To Drill. Permitted. LARGE PLAYSeeking 50% NonOperated Partner.Shallow Fayetteville Analog IP: 2,000 MCFD10-Year Term & 81.25% NRIEst Well Reserves: 2.0 BCFE/WellPipeline Ready. Infrastructure In Place.Completed Horizontal Well: $1.8 MM

DV 9853

GARVIN CO., OK PROSPECT5-Proposed Wells. ±200-Acres.Multiple Reservoir Potential.Total Depth: ~4,750 Ft. ~1.6 BCFELow-Risk Prospect. Pipeline Nearby.Up To 37.5% WI Available; 75% NRI (Lease)Offsets Recent 500 MCFD Completion.Est Reserves: ~100 MBO & 1.0 BCFGENERATOR HAS MORE DETAILS

DV 5425

APPALACHIA & EASTERNCLAY/LESLIE CO., KY PROSPECTS26,000+-Acres. Development Play.Multiple Pay Zones Identified. <3,200 Ft.600+-UnDrilled Development Locations.Excellent Horizontal Candidate.Complete Pipeline Infrastructure. DEVELOPMENT163-Wells Currently Producing.Production Can Increase w/ Treatment.>100 Mi Of Pipeline Infrastructure.SELLER HAS MORE DETAILS

DV 5295

KENTUCKY PIPELINE PROJECT15-Mile Line.NonOperated WI Available. PIPELINEOPERATOR SEEKS CAPITAL

G 9090PL

NORTHEAST PENNSYLVANIA OFFERMARCELLUS OPTION23,000-Acres On Contiguous Pipeline.Susquehanna River BasinDry Gas Window, 65% Brittle. MARCELLUS200+ Ft. Of Marcellus. 7,000 Ft. (TVD)4-Offset Horiz. Average IP: 7,350 MCFDPublished EUR: 5+ BCF/Well$500/Acre - Bonus/Prospect Fee/Acq FeeInitial 2-Year Lease2-Well Drilling Commitment (DC).After DC - 5-Year Option $2,500/AcreAdditional 5-Year Extension $2,500/Acre12-Year Total Primary Term.Seeking 75% WI Partner.Operations Are Negotiable.

DV 6433

OVERTON & PUTNAM CO., TNNatural Gas Pipeline. 120-Mile System.DIRECT CONNECT TO MAJORShallow Gas Wells. 900 Ft. - 2,000 Ft.In Area of MultiPay. Shows 7-Pay Zones.100% OPERATED WI FOR SALE PIPELINEPipeline Should Easily Take: 750 MCFDIn Area Of Deeper Exploration Activity.New Gas Available.Principals Only. Pipeline Only For Sale.

G 9000PL

POTTER CO., PA PROSPECT SALE3-Contiguous Blocks. ~9,000-Acres.APPALACHIAN BASINTargeting Marcellus Shale. MARCELLUSExcellent Pipeline Access.Leases Held By Production.50% - 75% WI Available; 83%-84.5% NRICONTACT EXPLORATIONIST FOR INFO

DV 5074

Not a client? Call (713) 650-1212.

Want More Listings?Clients can search PLS’ extensivelisting database at www.plsx.com.

On Tuesday, October 20, 2009, leading E&P executives will congregate at the Hilton of Americas Hotel,Downtown, Houston, TX for PLS’ 2nd Annual Playmakers Symposium and E&P Summit to discuss E&Pinitiatives and developments in today’s North American energy markets.

Grant Henderson, President of Talon has joined the ranks of Playmakers with his recent(controlling) purchase of Denbury’s Barnett Shale position. At the forum, Hendersonwill share his expertise and ideas on how the right play execution can maximize returnsin today's shale plays.

In addition to special sessions like Henderson's- Playmakers also includes a PowerLunch keynoted by Bobby Tudor, Chairman & CEO of Tudor, Pickering, Holt & Co.

Don’t miss your chance to be part of this exciting event, Reserve Your Seat‒Register Today! Go to our event website at www.plsx.com/playmakers

Take advantage of our low rates by registering before August 31st.For more information regarding event registration or sponsorship opportunitiesplease contact event coordinator, Samara Silverman, at ssilverman@plsx.com

Qualifier: PLS Playmakers Symposium and E&P Summit is a compliment to PLS’ DealmakersSymposium and A&D Forum in both USA and Calgary- these events are an extension/expan-sion of PLS’ Dealmakers Expos held from 1994-2000 in Houston, New Orleans, Oklahoma Cityand Calgary. PLS’ largest Houston Show was acquired by AAPG (Appex) and merged intoSummer Nape in 2005.

Playmakers Topics Include:

Samara SilvermanDirector of Communications & Conferences

713-650-1212ssilverman@plsx.com

www.plsx.com/playmakers

• Industry Trends: Domestic Joint Ventures as a Strategic Tool to Stimulate E&P in Turbulent Energy Markets • Foreign Investors Driving the E&P Market: Update on Recent Entrants in the E&P Marketplace & Plans for Development • Private E&P Companies Running & Gunning: Remaining Active in Tough Turf - A look at sustainability, development and projections for 2009 And much more...

• Accessing Capital in Tight Credit Markets: who's getting it and where is it going?• Resource Play Game Plan: What's Ahead for the Haynesville, Marcellus & Eagle Ford

Don’t Fumble This Date‒

10/20/2009@ Hilton Americas Downtown, Houston, TX

Bobby TudorChairman & CEO,Tudor, Pickering, Holt & Co.

Grant HendersonPresidentTalon Oil & Gas