LINN acquires, develops and maximizes cash flow from a growing portfolio of long-life oil and natural gas assets. Since inception, LINN continues to be one of the industrys most successful MLPs. Thanks to our people, strategy and assets we remain a leader in the industry.Visit www.linnenergy.com or call 281.840.4000 to learn more about LINN.LinEne_OGFJ_1503 1 2/26/15 8:46 AMAPRIL 2015THE EXECUTIVE PUBLICATION FOR THE OIL AND GAS INDUSTRYSPECIAL FOCUS:OFFSHORE RISK SHALE VS OFFSHOREGREAT CREW CHANGEHEDGING SURVEY RESULTSOPEC THROWSBOULDER IN RIVEROF ENERGY CAPITAL1504ogfj_C1 1 3/31/15 3:18 PM5221 N. OCONNOR BLVD.SUITE 1100IRVING, TEXAS75039(972) 432-1440IRVI NG HOUSTON SANTA FE STAMFORDwww.ngpenergycapital.comHatch Any New Ideas Lately?Capital and Sponsorship for the Natural Resources Industry Since 1988.1504ogfj_C2 2 3/31/15 3:18 PMBrian Tate | Energy & Natural Resources Group Headbrian.tate@regions.comWecreatedRegionsSecuritiestoprovidesmall-tomid-capcompanieswithhigh-qualityserviceandadvice from talented, relationship-oriented bankers. That means your business gets our dedicated A Team every time. Ourseasonedteamofenergybankersandengineersunderstandsyourcompanysdesireforgrowth,andour capital markets experience enables you to receive creative, customized solutions tailored to meet your companys strategic and nancial objectives. Fromcapitalraisinginthedebtandequitymarketstomergersandacquisitionsadvice,ourbankerscanset things in motion for your company. WALL STREET CAPABILITIES. MAIN STREET SENSIBILITIES.Structuring Advisor for theAcquisition of MoGas PipelineAdministrative Agent and BookrunnerNovember 2014------------------------ $93,000,000Senior Secured Revolving Credit Facility Joint Lead Arranger and Joint Bookrunner October 2014------------------------ $1,000,000,000------------------------ $2,000,000,000 Senior Secured RevolvingCredit FacilityJoint Lead ArrangerNovember 2014Corporate Banking | Capital Markets & Advisory Services | Dedicated Industry Experience 2015 Regions Securities LLC. Investment banking and business advisory services are offered through Regions Securities LLC, 1180 W. Peachtree St. NW, Suite 1400, Atlanta, GA 30309. Member FINRA and SIPC. Regions Securities LLC is an affiliate of Regions Bank. | Regions and the Regions logo are registered trademarks of Regions Bank. The LifeGreen color is a trademark of Regions Bank.Investment and Insurance Products:Are Not FDIC Insured | Are Not Bank Guaranteed | May Lose ValueAre Not Deposits | Are Not Insured by Any Federal Government AgencyAre Not a Condition of Any Banking Activity1504ogfj_1 1 3/31/15 3:25 PM2WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015CONTENTSFEATURESTHE EXECUTIVE PUBLICATIONFOR THE OIL AND GAS INDUSTRYOil&GasFinancialJournal(ISSN:1555-4082)ispublished12timesperyear,monthlybyPennWell,1421S.SheridanRd.,Tulsa,OK74112.PeriodicalsPostagePaidatTulsa,OK,andaddi-tionalmailingoffices.POSTMASTER:sendaddresschangestoOil&GasFinancialJournal,P.O.Box3264,Northbrook,IL60065.Changeofaddressnoticesshouldbesentpromptlywith oldaswellasnewaddressandwithZIPorpostalcode.Allow30daysforchangeofaddress.Copyright2015byPennWell.(RegisteredinUSPatent&TrademarkOffice.)Allrightsreserved. Permission,however,isgrantedforlibrariesandothersregisteredwiththeCopyrightClearanceCenterInc.(CCC),222RosewoodDrive,Danvers,MA01923,Phone(978)750-8400,Fax (978)646-8600,tophotocopyarticlesforabasefeeof$1percopyofthearticle,plus35centsperpage.PaymentshouldbesentdirectlytotheCCC.Federalcopyrightlawprohibitsunau-thorizedreproductionbyanymeansandimposesfinesupto$25,000forviolations.RequestsforbulkordersshouldbesentdirectlytotheEditor.Backissuesareavailableuponrequest.V12/NO.4|APRIL2015704630ON THE COVERSaudi ArabianOil MinisterAli Al-Naimi Northfoto/ Shutterstock.comDEPARTMENTS6EDITORS COMMENT8CAPITAL PERSPECTIVES12UPSTREAM NEWS14MIDSTREAM NEWS54DEAL MONITOR56OGFJ100P 64INDUSTRY BRIEFS67ENERGY PLAYERS80BEYOND THE WELL18 COVER STORYMANAGING THE CAPITAL CYCLEEnerComs James Constas offers an in-depth look at managing the capital cycle, detailing the need for industry participants to adapt in the cyclical oil and gas industry.16SHALE VS. OFFSHOREWhich will prevail in the long-term?28OFFSHORE OUTLOOKShort-term dip, long-term rise30FINANCING OFFSHORE ASSETSMarket conditions contrast sharply from those just a few months ago33IMPROVING OFFSHORE OPERATIONS37ADAPTING TO CHANGESAs complexity grows, companies must focus on capabilities, flexibility39HEDGING SURVEY RESULTS41GLOBAL SHALE IS LAGGING HERES WHYA proposal for GTW modular development 46PRICE OF CRUDE, COST OF DATA48THE GREAT CREW CHANGE51OIL AND GAS DISCLOSURE RULESPart three of a three-part series70SPECIAL REPORT: MEXICO 1504ogfj_2 2 3/31/15 3:25 PMEXPERIENCEMATTERSTRUSTYOURINVESTMENTTOAPROVENLEADERCuddEnergyServiceshasaprovenreputationforprofessionalism,reliability,and experience. We apply ingenuity and persistence to each operation to help you achieve the maximum return on your investment. With highly trained, certified crews located in major resource basins, we stand ready to deliver on time, every time.SIlMUL/IlCN CClLED IU8lNG & E-CClL HYDF/ULlC WCFKCVEF CEMENIlNG NlIFCGEN lNDUSIFl/L NlIFCGEN SLlCKLlNE & 8F/lDED LlNE ELECIFlC LlNE W/IEF M/N/GEMENI SFECl/L SEFVlCES WELL CCNIFCL1504ogfj_3 3 3/31/15 3:25 PM4WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015PennWell Corporation1455 West Loop South, Suite 400, Houston, TX 77027USA Tel: (713) 621-9720 Fax: (713) 963-6285www.ogfj.comVice President andGroup PublisherMark Petersmarkp@pennwell.comAssociate PublisherMitch Duffy (713) 963-6286mitchd@pennwell.comChief EditorDon Stowersdons@pennwell.com EditorMikaila Adamsmikaila@pennwell.comEditorial Creative DirectorJason T. Blair Contributing EditorsLaura Bell, David Michael Cohen, Paula Dittrick, Brian Lidsky,Debbie Markley, Per Magnus Nysveen, Tammer Qaddumi,Nick Snow, Imre Szilgyi, Don Warlick, John WhiteEditorial Advisory BoardE. Russell Rusty Braziel, RBN Energy LLCMichael A. Cinelli, Locke Lord LLP Mickey Coats, BOK FinancialAdrian Goodisman, Scotia Waterous (USA) Inc Cleve Hogarth, Quorum Business SolutionsBradley Holmes, Investor Relations ConsultantMaynard Holt, Tudor, Pickering, Holt & Co.Carole Minor, Encore CommunicationsJaryl Strong, BHP BillitonAndy Taurins, Lantana Energy AdvisorsJohn M. White, Roth Capital PartnersRon Whitmire, EnerVest Ltd.RegionalSales ManagerRobert McGarr (713) 963-6256rmcgarr@pennwell.comReprint SalesRhonda Brown (866) 879-9144 ext 194Fax: 219.561.2023 rhondab@fosterprinting.comSubscriber ServiceTo start or renew yoursubscription visitwww.ogfjsubscribe.com.To change your addressemail ogfj@halldata.comor call 847-763-9540.Circulation ManagerRon Kalusharonk@pennwell.comCustom PublishingRoy Markumroym@pennwell.comOfficial PublicationCORP. HEADQUARTERS1421 S. Sheridan Rd., Tulsa, OK 74112USAP. C. Lauinger, 1900 1988Chairman Frank T. LauingerPresident/Chief Executive Officer Robert F. BiolchiniChief Financial Officer/Senior Vice President Mark C. WilmothOGFJ.comFEATURED CONTENT Getup-to-datenewsandfeaturedcontentonOGFJ.comdaily. FindaQ&AseriesbyLockeLordfocusedonmanagingenergy sectordistress.ReadaboutrecentassetsalesbySouthwestern EnergyCo.,BentekanalysisofflatoilproductionintheBakken and Eagle Ford shale, and much more on OGFJ.com. SLIDESHOWS DrawingonthepopularityofourPhotooftheDayslideshow, werepleasedtoprovidereaderswithanotheropportunityto scrollthroughengagingphotosattachedtointriguingcontent. Find our Energy Players slideshow with links to OGFJ interviews featuring some of the industrys top executives. COUNTRY REPORTSHighlighting the oil & gas industries of Norway, Scotland, South Africa,Mexico,andmanymore,OGFJsCountryReportspage hosts a diverse selection of reports containing exclusive interviews withoilandgasleadersfromaroundtheworld,offeringan insiders view on whats hot in various markets.GET SOCIAL! New! Were introducing the OGFJ Showcase Page on LinkedIn. Followourpagetogetthelatestnewsandanalysisrighton LinkedIn.com.Asalways,youcanfindusonTwitter(@OGFJ) andFacebookandjoinotherpetroleumindustryexecutives, managers,analysts,andinvestorslookingforcredible,useful information about oil and gas industry developments. Become a part of our social community and join the discussion today!1504ogfj_4 4 3/31/15 3:25 PMenergycapital@macquarie.comThis information has been provided as a general overview only. Neither the information, nor any opinion contained herein constitutes an advertisement, a solicitation or an invitation by any member of the Macquarie Group to buy or sell any product or security nor offer any banking or nancial service or facility by any member of the Macquarie Group to any individual or entity. Macquarie Bank Limited maintains Representative Ofces in the states of New York, Texas and Illinois, but is not authorized to conduct banking business in the US or Canada.Macquarie Energy Capitals ability to understand and deliver on the complete spectrum of client needs has enabled the firm to fund $5.0 billion in energy finance transactions in the last 12 years. Mezzanine Debt Structured Project Finance 2nd Lien Debt Convertible Debt Preferred Equity Common Equity Public and Private Senior Debt Unitranche and Development LoansFinancial solutions for the global energy industryEUROPELevel 6, Ropemaker Place28 Ropemaker StreetLondon EC2Y 9HD+44 20 3037 4378ASIA-PACIFIC50 Martin PlaceSydney NSW 2000+61 2 8232 3333+61 8 9224 0666 (Perth)USA & LATIN AMERICAOne Allen Center500 Dallas, Suite 3250Houston, Texas 77002+1 713 275 8000 CANADATD Canada Trust TowerSuite 3100, 421 7th Avenue S.W.Calgary, Alberta T2P 4K9 +1 403 774 44491504ogfj_5 5 3/31/15 3:25 PM6WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015COMMENTARY AND OPINIONREP. ROB BISHOPEDITORSNOTE:JuliaBell,presssecretarytotheUSHouse CommitteeonNaturalResources,recentlysentmethiscom-mentary from Rep. Rob Bishop (R-Utah), committee chairman. I read it and immediately thought it would be an ideal piece to sharewithOGFJsreaders.So,inlieuofthismonthsEditors Comment from me, I am donating this space to Congressman Bishops comments. In the current stalemate between congres-sional Democrats and Republicans and between the legislative andexecutivebranchesofgovernment,thisperspectiveof-fers hope that we can, one day, end the current dysfunction in Washington. Don Stowers, Chief Editor - OGFJ As chairman of the Committee on Natural Resources, I will not regard assertions that conservation and economic development are in opposition. I will not condone rhetoric which hypes the possible origins of problems over solutions. From mitigating catastrophic wildfires and moving closer to energy independence, to increasing access to and modernizing our energy infrastructure on federal lands, we have shared goals and, with any hope, can move forward together.In lieu of the cane, a reflectionon conservation policyMORE THAN 200 YEARS AGO, Rep. Roger Griswold of Con-necticut used his wooden cane to bludgeon Rep. Matthew Lyon of Vermont on the floor of the US House of Representatives. Had Griswold any respect for Lyon, he would have challenged him to a duel.I raise the Griswold-Lyon affair of 1798 not to commend this conduct, but to show that despite todays political gridlock, it could be, and indeed has been, a whole lot worse. As a former history teacher, I believe history has invaluable lessons for policymakers because it reveals the range of consequences of policies that have been put into practice. Beyond mere study, it is through application of these lessons to the present that policymakers can learn which principlesstandthetestoftimeandwhichlawsmustbe modernized.Republicans and Democrats do have shared goals yes, even intheoft-controversialrealmofenergyandenvironmental policy.Both parties treasure our lands and want to see them healthy and pristine. Both parties want folks to be able to support their families. When it comes to the current policies that order how we conserve and utilize our nations resources, however, there is a major disconnect between our respective goals and solutions.This debate is mired in the premises and prejudices of the past, as we rely upon policies that were written for a different time when our country had different needs. Its an approach that no longer protects the land, yet leaves powerless the people who use that land. The sad truth is that a large portion of money spent at the federal level in the name of conservation and environmental stew-ardship will never reach the ground, nor deliver tangible benefits as its consumed by growing litigation costs and layers of prescriptive environmental regulations that cause more harm than good.On March 5, Department of the Interior Secretary Sally Jewel testified on the administrations budget proposal for fiscal 2016 before the House Committee on Natural Resources. After reviewing the administrations proposed request over the past month, my verdict is that it falls flat. Its a budget that looks like it was written for 1975, not 2016. Instead of addressing ongoing problems with our federal lands, water, oceans, and energy resources in a mean-ingful way, this budget proposes throwing thousands of gallons of cash and miles of new regulatory red tape to address problems which swallow up the time and resources of agencies like a bot-tomless pit. It is an example of the backwards thinking that suf-focates innovation and ingenuity.We should not accept a budget that relies upon this paradigm. I believe our nations leaders can do better.As chairman of the Committee on Natural Resources, I will not regard assertions that conservation and economic development are in opposition. I will not condone rhetoric which hypes the possible origins of problems over solutions. From mitigating cata-strophic wildfires and moving closer to energy independence, to increasing access to and modernizing our energy infrastructure on federal lands, we have shared goals and, with any hope, can move forward together.Our solutions will emerge from both the creative input of stake-holders and a new vision: 1) People come first in resource, energy and environmental policy, and stewardship is a shared responsibil-ity; 2) Natural resources give our nation opportunity and security; 3) Public lands, waters, and oceans are meant to be enjoyed by people and serve our nations needs; 4) Government should em-power people who know and love the land, when possible; and finally5)Governmentshouldbeaproblem-solver,nota problem-creator.Not all will agree on every policy route. That is fine. Disagree-ment does not quench my real hope that Republicans and Demo-crats can work together on shared objectives and creative solutions. People may say this is impossible, but I would point them back to that winter day in 1798, and posit that if Congress can surmount the tensions inherent in a public cane-fight, surely my colleagues in the 114th Congress can overcome whatever political rancor exists for the sake of a better present and a brighter future for the American people. 1504ogfj_6 6 3/31/15 3:25 PM1504ogfj_7 7 3/31/15 3:25 PM8WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015CAPITAL PERSPECTIVES Yakobchuk | Dreamstime.comUnlocking the value of oil and gas hedgesNOW IS THE TIME TO CONSIDER MONETIZING THIS VALUABLE ASSETAS A SOURCE OF FUNDING FOR 2015 OPERATIONSJAY SNODGRASS, ENERFI CAPITAL, NEW YORK, NYAJ MCNALLY, CLEARHEDGING, RED BANK, NJWITHWTIBREAKING$45earlierthisyearandhoveringaround $50 recently, many CFOs will struggle to fund operations in the com-ing months. In the current pricing environment, it has become more difficult to generate a positive risk-adjusted return from new drilling. This has led nearly every company to plan significant reductions to drilling budgets for the coming year.Manycompanies,however,haveexistingobligationsthatleave them little choice but to either drill uneconomic wells, pay delay rent-als, or risk losing valuable leases. With capital markets closed to all but the highest-rated companies, many CFOs are considering non-traditional funding options to meet these obligations.Fortunately many prudent operators put into place hedges that have insured cash-flows during this period of depressed commodity prices. However the value underlying these hedges is only realized on amonth-to-monthbasisascontractsexpire.Forcompanieswith ample liquidity this is fine, and monetizing hedges for these firms is generally not recommended as there is a cost to the process. How-ever, for firms in need of immediate capital, hedge monetization can provide a significant lump-sum payment. Further, the cost is typically lower than alternative sources of capital and can be completed in a matter of days rather than weeks or months.Maximizingnetproceedsfromahedgebookmonetizationre-quires specialized expertise and finesse. The first step in the process is to calculate an accurate valuation of the existing portfolio of hedg-es. Next its important to structure a new dynamic hedging program to ensure that production continues to be hedged throughout this volatile period. In addition, companies that have credit facilities in place will need to negotiate with lenders to minimize a likely reduc-tion in borrowing base. Finally, its important to minimize execution costs through price negotiation with counterparties, which can re-sult in tens of thousands of dollars of additional liquidity.Accurately valuing the existing hedge portfolio is critical as this is thesourceofproceeds.Mostcounterpartiesarelargecommodity trading desks that use sophisticated models to value hedge portfoli-os. As with any over-the-counter product, the pricing of derivative contracts is inefficient. Operators that arent able to accurately value 1504ogfj_8 8 3/31/15 3:25 PMAegis Energy Risk is a leading hedge advisory rm serving the oil & gas industry from the upstream to the downstream markets.We develop comprehensive strategies for our clients taking into account their specic nancial framework, overall commodity exposures and risk objectives.In addition to hedge strategy and transactional support, we also provide a full suite of back ofce services streamlining the operational and accounting requirements associated with protecting your company.Our clients rest easy knowing that we serve as their in-house risk management team.AEGIS ENERGY RISK (713) 344-0491info@aegis-energy.com www.aegis-energy.comChris Croom, President & CEOJustin McCrann, Executive VP TradingNick Curtis, Managing Director OriginationThe Missing Piece Comprehensive Hedge Advisory Services1504ogfj_9 9 3/31/15 3:25 PMLandmarkINTEGRATION + INFORMATION + MANAGEMENT19th International Conference on Petroleum Data Integration, Information and Data ManagementPETROLEUM DATAOwned & Produced by:Supported by: Follow us on: Presented by:May 1921, 2015Houston Marriott Westchase HotelHouston, TXwww.pnecconferences.comThe 2015 PNEC is a power-packed, two and a half days of technical program featuring 50 in-depth, how-topresentations and panel discussions. Numerous opportunities to network with your peers plus exhibitors from leading technology companies make this event one-of-a-kind. Changes in key technologies require innovative thinking and practical solutions to implement quality, data-driven decisions that meet enterprise-wide technical and nancial interests when millions of invested dollars are at risk. For 19 years this conference has been acclaimed for handling the discussion with balance.Full SponsorsOperators: Badge Holder Sponsor: Delegate Bag Sponsor: Full Sponsors With Exhibit Space:1504ogfj_10 10 3/31/15 3:25 PMAPRIL 2015 OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM11CAPITAL PERSPECTIVEStheir portfolio prior to negotiating the unwinding with counterpar-ties are at a significant disadvantage and could be leaving substantial moneyonthetable.Giventhecomplexitiesinvolved,itsgenerally advisable to have an independent qualified advisor on hand to en-surebestpracticesareimplementedandmaximumvaluation achieved.During the monetization process many companies will be tempt-ed to believe that oil has found a floor or that it cant go any lower and will therefore be reluctant to put on new hedges. This is a danger-ous trap that can spell future disaster. Hedging against lower prices is insurance against the systemic risk of an uneconomic business. Each operatorhasdifferentpainpointsandthenewhedgeprogram should be customized to protect against those particular pain points.Its important for operators to understand that hedges are simply an asset, in the form of insurance, that in most cases today has paid off handsomely.Nowisthetimeformanyoilandgascompaniestoconsider monetizing this valuable asset as a source of funding for 2015 opera-tions. Companies such as EnerFi Capital, ClearHedging, and others provide independent advice to operators interested in maximizing netproceedsfromhedgemonetizationandimplementingady-namichedgeprogramtoachieveongoingprotectionthroughout this volatile period. ABOUT THE AUTHORSJaySnodgrass(jay@enerficap.com)isaninvestment manager,speaker,andwriter.Heisthefounderand principal of EnerFi Capital, which provides specialized financialadvisoryservicestoclientsinNorthAmeri-canoilandgasdevelopment.Previously,Snodgrass workedinupstreamprivateequityfocusedonjoint venture investments in onshore drilling. He earned a BBA degree in finance and CIS from the University of Miami.AJMcNally(aj@clearhedging.com)isthefounderof ClearHedging. He brings a depth of experience in ana-lyticalresearch,clientrelationships,leadership,man-agement, and market knowledge. He began his career in New York City with E.F. Hutton and Citibank as an equity analyst where he valued and sold assets heldin trust and estates. In his 30-year trading career, McNally has traded futures and options on the NYMEX, COMEX, and NYBOT in various energy,metal,andsoftproducts,includingnaturalgas,crudeoil, gold, silver, cotton, and sugar. He holds a degree from Villanova Uni-versitys business school. U.S. ENERGYDevelopment CorporationWe Will Work With You! Call Us Today:800.636.7606 x 238 www.usedc.comUWe800We are currently looking to acquire oil and natural gas assets in the following areas:We are also seeking additional leasing opportunities in Texas and Oklahoma(ground hoor or targeted acquisitions).llowing areas: fole are also seeking additional leasing We Anadarko Basin Fort Worth Basin AppaIachian Basin Permian Basin WiIIiston BasinCurrentIy Acquiring OiI & NaturaI Gas Assets!Contact: Prospects@usedc.comTrusted Operator & Capital Providerfor over 30 Years1504ogfj_11 11 3/31/15 3:25 PM12WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015UPSTREAM NEWSB R I E F SGULF OF MEXICO DRILLING SALEForty-two companies pledged $583.2 million bidding on 169 central Gulf of Mexico tracts during a government auction that took place on March 18. The gov-ernment is set to collect approximately $538.8 million in expected winning bids, down significantly from a March 2014 central Gulf of Mexico auction that raked in $850.8 million in winning bids from 50 companies. 2015 WORLD OIL DEMAND UP SLIGHTLY OPEC adjusted its 2015 world demand forecast slightly higher, to 92.32 MMbpd. Demand by developing countries is expected to outpace growth rates from China, which is expected to experience another round of decelerated demand growth. OPEC is forecasting 820,000 bpd of YoY growth in oil demand from develop-ing countries in 2015, well ahead of the 310,000 bpd growth expected to be seen by China. DOUGLAS WESTWOOD: UK OFFSHORE OIL & GAS WHAT NEXT?The low oil price is expected to dramatically im-pactO&GactivityontheUKCS.Mostnotably, the number of wells drilled will decrease par-ticularlyE&Awells.In2014,drillingcampaigns were significantly smaller than forecast only 14 exploratory wells were drilled from an anticipated 25. This is the lowest number since 1970 and with the current oil price an increase is highly unlikely. However,productionisexpectedtobemain-tained over the short to mid-term, bolstered by sanctionedprojects.Meantimeoperatorsare seeking to control costs BP and Talisman have recently announced large job cuts and many high CapEx developments will face delays. Despite the downturn, the 28th licensing round (Nov 2014) appears to indicate continued Oper-ator interest. DECC awarded a total of 134 licenses fewer than the record 27th round in 2012 but still demonstrating the ongoing attractiveness of the region. This does not mean drilling will return tohigherlevels:themajorityoflicenseswere awarded on the basis of further analysis of seismic data.Overall,oilcompaniescommittedtojust five firm wells and four contingent wells.Given thedecliningoilpriceandcurrentunattractive fiscal regime, a lack of commitment from oil com-paniesistobeexpected.However,thelackof drilling activity still represents a significant con-cern for the UK industry and encouraging com-panies into drilling will require careful restructur-ing of both the fiscal and regulatory framework. Chancellor George Osborne, in his Autumn Statement, announced plans to revise the fiscal regimeandappointanewregulator.However, given the steep decline in oil price, more needs to be done, particularly on taxation indeed Lord John Browne recently suggested cutting through the tax complexity and putting it onto a corpo-ration tax basis. However, much depends on the outcome of the general election anything but a win for Conservatives may delay much needed reformsandsuppresstheUKCSO&Gindustry further.MEXICOS BIDDING ROUNDFOR SHALLOW WATER KICKS OFFThe Mexican National Hydrocarbons Commission recently published the bidding and contract terms for the first 14 oil and gas areas in shallow waters, kickingoffthefirstphaseofMexicosbidding round for exploratory oil and gas blocks in the Gulf of Mexico.However, with the recent plunge in oil prices, many are speculating whether major international oilcompanieswillcontinuetoshowinterestin theinitialphaseofthebiddinground.Mexico took note and revised its initial offering by elim-inating a few costly shale fields from its private oil tenders.In the past week, the government has admit-ted that it may need to further delay high-cost areas,suchasunconventionals,statedAdrian Lara,GlobalDatasseniorupstreamanalystfor the Americas, in a released statement. On top of this, the new schedule appears ambitious for aregulatoryagencyorganizingitsfirst-everli-censing round.Despite these delays, the lower oil price should not affect the competitiveness of bidding on the shallow-water exploration blocks where produc-tion costs are less than $20/bbl, remarked Juan Carlos Zepeda, head of the National Hydrocar-bons Commission. NHC is the regulatory over-seeing Mexicos Round One.Several major companies, including ExxonMo-bil, Chevron Corp., Shell, Ecopetrol SA, and BG Grouphavepaida$350,000fee(ontopofa $18,600 registration fee) for access and authori-zation to the data room that houses seismic and geological data that has been the exclusive pre-serve of state oil company PEMEX for nearly eight decades.Companies are slated to review the material which will open up to the bidding and contract terms for the first 14 oil and gas areas in shallow waters in the first phase of round one. According to a recent Mayer Brown report, these exploratory areas, located off the coast of the states of Vera-cruz, Tabasco, and Campeche in southeast Mex-ico, hold prospective resources that are expected tocontainlightcrudeoilwithlowproduction costs. Each contract area is subject to different minimum investment obligations.In the first round, the bidding process is divided into the following five different phases: Shallow waters,extra-heavyoil,ChicontepecBasinand unconventional resources, onshore deepwater.PEMEX, like other companies, can bid on no more than five of the 14 areas on offer in the first tender. But with the depressed oil prices, author-ities were redefining what can be offered, stated Zepeda.TheEagleFordshalehasgeological continuation of formations that cross into Mexico, but technical challenges, including lack of infra-structure and water and swift production times correlate to costs that are not attractive during a 1504ogfj_12 12 3/31/15 3:25 PMAPRIL 2015OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM13UPSTREAM NEWSB R I E F SBOTTOM FOR OIL SERVICE STOCKSIn a February report, Sterne Agee analysts looked at rig momen-tum as a factor to help indicate where the oil service industry would hit bottom. One key factor historically linked to the bottom for oil service stocks has been a slowdown in the pace of the drop in rig activity. Owing to the historically sharp decline in activity, this point will likely arise sooner in this downturn than prior drops, the analysts noted. At the time of the report, the industry began to see signs of deceleration in the pace of the rig count decline.down cycle. The commission along with the En-ergy Ministry will decide by 2Q 2015 which areas will be trimmed.The first deepwater Mexican prospects due to be auctioned later this year remain attractive even in the current environment because production is at least eight years away, meaning current prices are less relevant to exploration budgets for com-panies assessing their existing portfolios.Moreover, in 2015, Mexico plans to award per-mits for companies to conduct seismic studies, includinganassessmentofpresaltprospects. Two-dimensional and 3D studies conducted by outside parties will be a first for the country.I think what Mexico has accomplished recently is outstanding for two reasons: a) the number of years that the Mexican industry has been closed and b) the emblematic nature of oil in Mexico, stated Gabriel Salinas, associate, Mayer Brown, to Offshore. In one year, a major reform occurred with new energy laws and regulations set in place. Theyve done their homework and Im excited to see this process begin.Robin Dupre, Offshore IEA RAISES FORECAST FOR OIL DEMANDHaving bottomedout in the second quarter of 2014, global oil demand growth has since steadily risen, with yearonyear gains estimated at around 0.9 MMbpd for the final quarter of last year and 1.0 mb/d for the current quarter, said the Inter-national Energy Agencys (IEAs) Oil Market Report for March. The forecast of demand growth for all of 2015 was raised by 75 kb/d to 1 MMbpd, bring-ing global demand to an average 93.5 MMbpd. Global supply rose by 1.3 mb/d yearonyear to an estimated 94 MMbpd in Feb., led by a 1.4 MMbpdgaininnonOPECoutput.Declinesin the US rig count have yet to dent North American outputgrowth.FinalDec.andpreliminarycur-rent-quarter data show higherthanexpected US crudesupply,raisingthe2015NorthAmerican outlook.OPEC crude output edged down by 90 kb/d in February to 30.22 mb/d, as losses in Libya and Iraq offset higher supply from Saudi Arabia, Iran, and Angola. The slightly higher demand forecast has raised the call on OPEC crude for the sec-ondhalfof2015to30.3MMbpd,abovethe groups official 30 mb/d target.Global crude refinery throughputs estimates have been raised to 77.8 MMbpd for the current quarter and 77.3 MMbpd for the second quarter onsustainedhighmarginsandaslightlymore robustoildemandoutlook.Annualgainsare forecastatabout1MMbpdforthefirsthalfof 2015,downfromasharp2.2MMbpdthefinal quarterof2014andinlinewithprojectedoil product demand growth.OECDcommercialstocksrosebyaweakerthanaverage 23.1 MMbbl in Jan. US crude stocks rose to a record 72 mb surplus. WOODMAC: OIL SANDS CASH FLOWSTO FALL BY $23B IN NEXT TWO YEARSThe operational cost of extracting bitumen from Canadas oil sands tops out at $37 per barrel for in-situprojectsand$40perbarrelformining projects, according to Wood Mackenzie. CallanMcMahon,principalanalystWood Mackenzie, says this is among the highest of all project types globally. With low oil prices, the oil sands regions cash flows will fal l by $23 billion in 2015 and 2016 combined, he said.Thefirmforecaststhatcapitalspendinthe region will fall by $1.5 billion over the next two years(4%from4Q14assumptions),butitsees limited impact on production.Even if projects temporarily operate at a loss, shut-insarenotexpected;andwiththecosts sunk,projectstotaling458,000b/dofbitumen are set to start production in 20152016, McMa-hon said. In addition, the analysis highlights that decreased investment will show post-2017, and the 4 million b/d peak bitumen production pre-viously expected in 2020 by Wood Mackenzie has now been pushed out to 2024.Theoilsandsremainviablelong-term:An average point forward breakeven for an onstream in-situ project is $41/bbl and the average point forward breakeven for an onstream mine is $47/bbl (WTI indexed), but full-cycle breakevens can exceed US$100/bbl for both project types.Larger and diversified companies better po-sitioned to weather the storm: Imperial, CNRL, Suncor, and Shell each still hold over $20 billion in post-tax remaining NPV10 in the region.To date, over $35 billion of value has evapo-rated from the region. If prices stay low, at a $60/bbl real flat price deck, the firm calculates that another $121 billion could be at risk, which equals with the Eagle Fords remaining value. Companies lookingfortheexitmightfindlimitedoptions: The large amount of investment made in the past decade by the potential suitors and the unique expertise required to develop this high-cost re-source are both significant headwinds. 1504ogfj_13 13 3/31/15 3:25 PM14WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015MIDSTREAM NEWSB R I E F SWOODSIDE CLEARED TO ACQUIRE APACHES STAKES IN LNG PROJECTSThe Australian Com-petition and Consumer Commission (ACCC) said March 5 that it will not oppose Woodsides proposed acquisition of Apache Corp.s interests in the Wheatstone, Bal-naves, and Kitimat proj-ects. The Wheatstone and Balnaves projects are located in the North-ern Carnarvon Basin, off-shore Western Australia, while the Kitimat project is located in British Columbia, Canada. Woodside and Apache overlap in the wholesale supply of natural gas to the domestic market in Western Australia. While the ACCC determined that the proposed acquisition would be un-likely to raise significant competition concerns, it acknowledged concerns expressed by the market about the effects of any further industry consoli-dation.TEXAS LNG FILES WITH FERCTO COMMENCE PREFILING PROCESSFOR BROWNSVILLE LNGPROJECT On March 9, Texas LNG Brownsville LLC initiated the US Federal Energy Regulatory Commission pre-filing process, starting the regulatory review fortheproposedliquefiednaturalgas(LNG) exportfacilityinBrownsville.TexasLNGplans tobuildtheBrownsvilleprojectintwophases, each with LNG production of 2 million tonnes per year(MTA).PendingFERCsfinalapprovalto constructtheproject,Phase1isexpectedto commence production in 2020. Texas LNG has executed an amendment to its Option to Lease Agreement with the Brownsville Navigation District in Cameron County to upgrade to a 625 acre site with deepwater frontage to the Port of Brownsville shipping channel.The new site is located approximately five miles from the mouth of the Gulf of Mexico on the north side of the channel. Texas LNGs equity and engineering partner, SamsungEngineeringCo.Ltd.hasassigneda team of engineers and project staff at its Global Engineering Center in Seoul, Korea to lead the engineeringphaseoftheprojectwithsupport fromitsHouston-basedNorthAmericanhead-quarters.As of the end of February 2015, Sam-sungEngineeringhascompletedfourmonths out of the 12 month Front End Engineering and Design study and over 50,000 cumulative man-hours of engineering.Texas LNG is being sup-portedbyitsownersengineer,BraemarEngi-neering, and environmental consultant, Natural Resource Group (NRG).ENCAP FLATROCK INVESTS UPTO $750M IN MODA MIDSTREAM Moda Midstream LLC, a liquids terminaling and logisticsprovider,hassecuredaninitialequity commitment of $750 million from EnCap Flatrock MidstreamandtheModamanagementteam. Modawasformedearlierthisyeartoprovide independent terminaling, storage and distribution solutions to refiners, petrochemical manufactur-ers, marketers and producers of crude oil, con-densate, NGLs, refined products and other bulk liquids.Modasexpertiseincludesdeepwater vessel loading and unloading, storage, blending, processing and pipeline operations. ModaMidstreamisledbyitsfourfounding partners, president and CEO Ken Owen; senior vicepresidentofcommercialandbusinessde-velopment Bo McCall; senior vice president and CFOJonAckerman;andseniorvicepresident andCOOJavierdelOlmo.Modasfounding partnersworkedtogetherasmembersofthe executive team at Oiltanking North America LLC and its publicly traded affiliate, Oiltanking Partners LP. ModaMidstreamwasadvisedbyVinson& Elkins and Crain, Caton & James. EnCap Flatrock was advised by Thompson & Knight.ANADARKO JOINS MAGELLAN,PLAINS ALL AMERICAN TO BUILDSADDLEHORN PIPELINEAwholly-ownedsubsidiaryofAnadarkoPetro-leum Corp. has exercised its option to purchase a 20% equity interest in Saddlehorn Pipeline Co. As a result, the equity ownership in Saddlehorn will be 40% Magellan Midstream Partners, 40% PlainsAllAmericanPipelineLP,and20% Anadarko. Saddlehorn is a limited liability company that will construct, own and operate the Saddlehorn pipeline, an approximately 550-mile pipeline that will transport various grades of crude oil from the DJBasin,andpotentiallythebroaderRocky Mountain area resource plays, to storage facilities in Cushing, OK owned by Magellan and Plains. The 20-inch pipeline will have an ultimate capacity to transport up to 400,000 barrels per day (bpd), but the initial capacity of the Saddlehorn pipeline is expected to be closer to 200,000 bpd. AnextensiontoCarr,COisalsoundercon-siderationforconnectiontoexistingcrudeoil assets owned by Plains in that region. The project is currently estimated to cost be-tween$800millionand$850million.Magellan will serve as construction manager and pipeline operatoroftheSaddlehornsystem.Subjectto necessary permits and regulatory approvals, the Saddlehorn pipeline is expected to be operational during mid-2016. EQT TO SELL WEST VIRGINIAGATHERING SYSTEM FOR $1BEQT Midstream Partners LP has agreed to acquire the Northern West Virginia Marcellus Gathering System from EQT Corp., along with a preferred interestinanEQTsubsidiary,for$1.05billion. EQT will receive $997.5 million in cash and $52.5 million in common and general partner units. In addition,thepartnershipwillfund$370million of system expansion projects over the next several years.The gathering system was designed and con-1504ogfj_14 14 3/31/15 3:25 PMAPRIL 2015OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM15MIDSTREAM NEWSB R I E F SENLINK COMPLETES CORONADO ACQUISITION The EnLink Midstream companies, EnLink Midstream Partners LP and EnLink Midstream LLC, have completed the acquisition of Coronado Midstream Holdings LLC, which owns natural gas gathering and process-ing facilities in the Perm-ian Basin, for approxi-mately $600 million.WILLIAMS SEEKS FERC APPROVAL FOR PIPELINE EXPANSIONWilliams said March 19 that Transco has filed an application with the US Federal Energy Regula-tory Commission (FERC) for its Dalton Expansion Project, which would support providing Mar-cellus shale gas to the Southeast for electricity generation and local natural gas distribution.Construction is planned to begin in the third quarter of 2016, with completion targeted for 2017, subject to all necessary or required ap-provals by FERC and all other regulatory bodies.structed to gather natural gas production in the wetgasanddrygasregionsoftheMarcellus; specifically in the Saturn, Mercury, Pandora, and Plutodevelopmentareas.Thesystemincludes 70milesofnaturalgasgatheringpipelineand ninecompressorunitswith25,000horsepower of compression. In addition, the system includes a 30-mile, high-pressure wet gas header pipeline that moves wet gas from the development areas to the MarkWest Mobley processing facility. EQT contractedfor10yearsoffirmcapacityonthe system.EQT Midstream Partners LP expects to install 100 miles of gathering pipeline and five compres-sor units with 23,700 horsepower of compression over the next several years. Ongoing maintenance capitalexpendituresrelatedtothesystemare forecast to be less than $5 million per year.EQT currently holds 76,000 net acres in north-ernWestVirginiathatsurroundtheacquired gathering system, including 59,000 net undevel-oped acres. As of Dec. 31, 2014, there were 199 Marcelluswellsand20UpperDevonianwells being serviced by the gathering system, with an average daily gathered volume of approximately 410 MMcf per day.Thetermsoftheacquisitionwereapproved by the Conflicts Committee of the board of di-rectors of EQT Midstream Services LLC, the gen-eral partner of the Partnership (General Partner), which is composed entirely of independent di-rectors. The committee was advised by Evercore Group LLC regarding financial matters; and Rich-ards, Layton & Finger PA regarding legal matters. The General Partner and its affiliates were advised by Baker Botts LLP.BEAR HEAD LNG RECEIVESPERMIT TO CONSTRUCT The Nova Scotia Utility and Review Board (UARB) has issued Bear Head LNG Corp. an updated and amended Permit to Construct, making the project thefirstinEasternCanadatobegrantedsuch authorization.Theapprovalfollowedarecom-mendationfromLloydsRegister,theUARBs certifyingauthority.BearHeadLNGhasnow obtained nine of the 10 initial Canadian federal, provincial, and local regulatory approvals needed to construct a liquefied natural gas export facility on the Strait of Canso in Nova Scotia. The UARB first permitted Bear Head LNG as anLNGimportfacilityin2005.Facilitieswere partially constructed and have been kept in hotidlestatussince2008.TheUARBpreviously granted extensions of the Permit to Construct in 2009 and 2013. On February 9, 2015, the Canadian Environmental Assessment Agency (CEAA) issued a letter concluding that the Bear Head LNG proj-ect is substantially the same as the project pre-viously approved by CEAA. As a result, no further agency review is required.The last of the 10 initial Canadian environmen-tal and engineering approvals required is an up-dated and amended registration document which will soon be filed with Nova Scotia Environment (NSE),theprovincialgovernmentdepartment withabroadmandatetoprotectthe environment Bear Head LNG has submitted project descrip-tioninformationtothedepartmentandantici-pates NSE approval of this permit amendment in the second quarter of this year. Once construct-ed, the Bear Head LNG project will have an initial production capacity of 8 million tons per annum (mtpa) of export LNG.Project timing depends on regulatory approval, as well as contracts with gas suppliers and LNG buyers.Withoutmajordelaysintheregulatory process,thefacilitywouldbeinoperationby 2019.The Bear Head LNG site is located on the Strait of Canso in Point Tupper, Richmond County, Nova Scotia, which is about half the shipping distance to major European markets compared to US Gulf Coast ports, and is closer than its North American competitors, including those in British Columbia, to other burgeoning natural gas markets such as India.HEP EXPANDS INTO MARCELLUS Howard Midstream Energy Partners LLC has ex-ecuted a definitive purchase and sale agreement withSouthwesternEnergyCo.topurchasethe companysnortheastPennsylvanianaturalgas gathering assets in Bradford and Lycoming coun-tiesfor$500million.Thesystems,servingthe Marcellus region, include 100 miles of natural gas gatheringpipeline,withnearly600MMcf/dof capacity. In addition to the existing systems, HEP planstodesign,construct,andoperateanew naturalgasgatheringsystemforSouthwestern Energy in Tioga County. Once fully operational, thenewsystemisexpectedtoaddupto380 MMcf/d of capacity in the area. The transaction is expected to close 2Q15. HEP, which is based in San Antonio, Texas, plans to open an office in Pennsylvania upon the transactions closing. 1504ogfj_15 15 3/31/15 3:25 PM16WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015F2:GLOBAL LIQUIDS PRODUCTION FROM OFFSHORE AND SHALESource: Rystad Energy UCube 20052006200720082009201020112012201320142015OffshoreOnshore30,00025,00020,00015,00010,0005,0000kbbl/dF1:GLOBAL OFFSHORE AND SHALE E&P INVESTMENTSSource: Rystad Energy UCube 2005200620072008200920102011201220132014400350300250200150100500US$ BillionsOffshoreShaleASARESPONSEtoloweroilprices, E&P companies have guided consider-able cuts in their 2015 investment bud-gets.Preliminarybudgetsindicatea ~20% drop in global E&P investments this year, with shale declining the most.Doesthismeanoffshoreismore competitive than shale, and how have these sources performed historically?Observinghistoricaltrends,Figure 1 shows global investments for offshore and shale oil and gas. During the past decade, offshore investments have in-creased from ~ US$150 billion in 2005 to ~ US$360 billion in 2014. The growth in offshore investments is a combina-tion of higher activity and higher unit costs (i.e., rig rates). Also over the last 10years,shaleactivityacceleratedas horizontal hydraulic fracturing became provenandeconomical.Asaresult, investmentsincreasedfromalmost zero to ~ US$160 billion in 2014. Figure 2 shows the change in produc-tion resulting from investments. While incurringincreasinglymorecosts throughouttheperiod,offshorepro-ductionremainedlargelyunchanged at 27 MMboe/d. Shale production, on the other hand, showed robust growth, increasingfromlessthan100kboe/d in 2006, to an estimated ~7,500 kboe/d in 2015. The reactiveness of the produc-tion to the investments is largely a fac-tor of the life cycle.Offshore drilling has been prevalent since the 1960s and has a large accrual ofdeclininglegacywells.Eachyear, operators must drill more wells just to offset the natural decline from histori-cal wells. Shale is relatively immature, with significant activity levels starting in2008.Therefore,operatorsareable to build up production with each new well drilled. Looking into short-term investment budgets, 2015 E&P activity will be ~20% lowerthan2014levels.Shale-focused Offshore vs. shaleWHICH WILL PREVAIL IN THE LONG-TERM?PER MAGNUS NYSVEEN AND LESLIE WEI, RYSTAD ENERGYcompanies have reduced expenditures by ~30%, and non-shale counterparts have decreased their expenditures by 11%. This implies that shale-focused companies are more flexible to a short-term price collapse and are able to be more reactive in the budgeting. Companies with exposure to both shale and offshore production (ConocoPhil-lips, Noble Energy, and Murphy Oil), have decreased their budgets for shale spend-ing by ~50% in 2015, but only adjusted the offshore budget by ~10%. This reflects the flexibility of each segment. Operators can drop shale rigs more quickly than offshore rigs due to contract agreements and have fewer commitments when it comes to infrastructure. 1504ogfj_16 16 3/31/15 3:25 PMAPRIL 2015OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM17F3:KEY ECONOMIC METRICS FOR SHALE AND OFFSHORESource: Rystad Energy research and analysis90 USD/bbl70 USD/bblPrincipalsourcePayback time*YearsIRR*%Brent breakevenoil price*USD/bbl*Estimates are based on the 30 largest projects within each group expected to start up in the period 2014-2020. Shale/tight oilUltraDeepwaterDeepwaterShallowwater61 71 77 642411 12121491119%14% 35%24% 14%10% 13%9%Overthelastfiveyears,shalehas experiencedextraordinarydevelop-ment, delivering much higher produc-tion growth than offshore. The flexibil-ityofthissourcegivesoperatorsthe option to reduce activity quickly when pricesdrop.Intermsofeconomics, shale is still a very competitive source of production and will be the fastest to recover once oil prices increase. ABOUT THE AUTHORSPer Magnus Nysveen is se-niorpartnerandheadof analysis for Rystad Energy. Hejoinedthecompanyin 2004. He is responsible for valuationanalysisofun-conventional activities and is in charge of North American Shale Analysis. Nys-veenhasdevelopedcomprehensive models for production profile estima-tions and financial modeling for oil and gas fields. He has 20 years of experience within risk management and financial analysis, primarily from DNV. He holds anMScdegreefromtheNorwegian University of Science and Technology and an MBA from INSEAD in France.Leslie Wei is an analyst at RystadEnergy.Hermain responsibility is analysis of unconventionalactivities inNorthAmerica.She holds an MA in economics fromtheUCSantaBarbaraandaBA ineconomicsfromthePennsylvania State University.Companies with exposure to both shaleandoffshoreproduction (ConocoPhillips,NobleEnergy, MurphyOil),havedecreasedtheir budgetsforshalespendingby ~50%in2015,butonlyadjusted the offshore budget by ~10%. Op-eratorsareabletodropshalerigs more quickly than offshore rigs due tocontractagreementsandhave fewer commitments when it comes to infrastructure.It is clear that operators are able and willing to decrease shale activity faster thanoffshoreactivity,butitisstillimportanttoreviewtheeconomicsofeach source. Figure 3 looks at three economic performance benchmarks: break-even oil prices, payback time, and IRR. Shale and ultra-deepwater fields have the lowest break-evenpricesatUS$61andUS$64,respectively.Intermsofpaybackyears, shaleismuchmoreattractivewithfouryearsbeforepayback,assuminganoil price of US$70/bbl, compared to 11 years for ultra deepwater. 1504ogfj_17 17 3/31/15 3:25 PM18WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015Ali bin Ibrahim Al-Naimi, Saudi Arabias Minister of Petroleum and Mineral Resources since 1995, arrives at an OPEC meeting in Vienna, Austria. Al-Naimi served as president and CEO of Saudi Aramco prior to his appointment as oil minister. Northfoto/Shutterstock.comJAMES CONSTAS, ENERCOM INC., DENVERCYCLICAL OIL AND GAS INDUSTRY REQUIRES ADAPTABILITY BY INDUSTRY PARTICIPANTSManaging the capital cycleCAPITAL IN the oil and gas industry can be likened to water, in that it flows from markets to companies and is then invested into finding and developing resources. Water is energy and just over 100 years ago river resources were harnessed to power sawmills and grain mills. Water is still required to grow food, of course, and irrigation remains a key ingredient in feeding six billion hungry mouths in the modern world.Today, those mills are powered by electricity, some of which is generated by hydroelectric dams, but increasingly more likely created by natural gas-burning generators. Water follows its own cycle, and so does capital. If water seeks the lowest point driven by gravity, then capital allocated by managers seeks the highest returns, and generates more value (i.e., return on capital) that can be reinvested into more projects, perpetuating the cycle, so long as there is demand for the resource. Perhaps in no other industry than oil and gas is the capital cycle on full display. Since 2008, a river of capital has flowed into the upstream sector of the North American oil and gas industry. One large boulder that fell into this metaphorical river, however, was OPECs 2014 Thanks-giving Day Turkey Surprise in which swing producer Saudi Arabia decided against cutting crude production, even symbolically, to defend oil prices. Foreshadowing Saudi Arabias thinking about crude oil prices, on Feb. 4, 2011, Saudi Arabian Oil Minister Ali Al-Naimi said prices nearer $75 would be appropriate. On Feb. 3, 2011, Brent was at US$103.37 in intra-day trading.Brent closed at US$55.91 on Mar. 8, 2015.Proving that sometimes doing nothing is an act in itself, the futures markets took the November 27, 2014, OPEC non-decision as confirmation that oil markets were oversupplied, which led to the current environment of weak commodity prices. West Texas Intermediate, the primary North American crude benchmark, closed at $48.84 per barrel on March 13, 2015, 54% lower than the same time last year. The crude oil price drop has disrupted the flow of funds to projects worldwide and resulting in significant losses of jobs and value. At Mar. 13, 2015, the market value of US independents was $144.8 billion lower than the same time last year, a stunning 25% loss of value for a 78-company subset of EnerComs E&P database. The stock prices of only six E&Ps rose during the 12-month period, and the magnitude of losses ranged from a low of minus 3.8% to a 1504ogfj_18 18 3/31/15 3:25 PMAPRIL 2015OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM19F1:WHAT IS A GROWTH COMPANY?80.0%60.0%40.0%20.0%0.0%20.0%40.0%60.0%80.0%100.0%120.0%140.0%100% 50% 0% 50% 100% 150% 200% 250% 300%3-year shale price appreciation3-year debt-adjusted production growth per shareR2 = 0.7741F2:US E&P CAPITAL RAISES0%10%20%30%40%50%60%70%80%90%100%$45,932$37,786$12,684Millions of dollarsYear2010 2011 2012 2013 2014IPOSecondary equity Debt$37,246$12,299$4,429$39,233$14,296$3,465$60,843$14,522$5,587$41,469$15,978$3,511high of minus 91.9%.The action of one country making uni-lateral policy for one global commodity has produced profound effects on an entire industry, not to mention government re-ceipts, employment, and consumer spend-ing. If we needed any reminder that we live in a global village, the action of one country has indeed impacted the entire world. The reaction to the new price environ-ment has been swift and decisive. On Friday, Mar.13,2015,theBaker-Hughesoilrig count stood at 866, a 56-rig drop from the previous week and 595 lower than the same time last year, equivalent to a 41% decline. We have to look back to Oct. 2, 2009, to find the oil rig count at current levels, and then WTI was $107.94 per barrel. From a purely rational economic point of view, the industry has reacted exactly as an economist would have predicted. As price-takers, oil and natural gas producers have little to no control over the price of their products. Falling commodity prices are tantamount to transforming a life-giving rain shower capable of recharging the river of capital into a light drizzle, insufficient for generating funds for reinvestment and erodingthereturnsondevelopment drilling. As a client CEO said to us in San Fran-cisco during EnerComs The Oil & Services Conference, This isnt a cycle. This is a steamroller that just hit us.Lookingbackatthe12-monthfor-ward-curve for crude oil prices (WTI) start-ing in January over the past five years, the forward curve has been in some form of backwardation(excludinggeo-political spikes) between 2012 and 2015. Starting around the beginning of January 2015, the curve was in contango, and CFOs could lock in higher future oil prices tomorrow than at spot prices today.In the current environment, manage-ment teams have substantially cut capital allocated to drill and pivoted towards cap-ital preservation for enduring this current down cycle. In this article, we examine what management teams are doing to achieve these goals and share some observations on the cycle of conserving, raising, allocat-ing, and generating capital in the upstream sector.THE SILENT THIEFInflation has often been called the silent thief, to describe the pernicious effect of rising prices on household budgets, especially those on fixed incomes. In the oil and gas business, resource depletion is the silent thief that works against corporate growth goals. In many ways, the upstream business behaves like the car business. We have all been seduced by the aroma of new car smell, that alluring combination of aromas from new plastic, supple leather seats, and fresh carpet. Combined with an exterior free of parking lot dings and paint chips on the outside and a Blaupunkt premium sound system that makes us feel like we are listening to Pavarotti at Carnegie Hall on the inside, suddenly were hooked! Once we drive off the lot, our rolling opera house instantly loses 20% of its value. In two years, we will be fortunate if our vehicle loses only 30% of what we paid on the showroom floor.Since most unconventional wells drilled in North American resource plays will produce about 30% of their total estimated recovery within the first two years, suddenly a 20% depreciation hit on a new car doesnt sound all that bad. In fact, EnerComs well economics model for the typical Bakken oil shale well forecasts a 65% first-year decline in the pro-duction rate and estimates total production of 220,000 barrels of oil equivalent in the first 1504ogfj_19 19 3/31/15 3:25 PM20WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015F3:NET DEBT/EBITDA (TTM 9/30/14)Companies operating primarily in resource playsMedian net debt/EBITDA 2.0xAvg. change in equity pricesABCDEFGHIJKLMNOPQRSTUVWXYZAABBCCDDEEFFGGHHIIJJKKLLMMNNOOPPQQRRSSTTUUVVWWXXYYZZAAABBBCCCDDDEEEFFFGGGHHHIIIJJJKKKLLLMMMNNNOOOPPPQQQRRRSSSTTT UUU VVV 5.0x0.0x5.0x10.0x15.0x20.0x25.0x two years of its life, or about 30% of the wells total estimated ultimate recovery (EUR). Although we write for a savvy audience, emphasizing the decline curve at the outset is important, because it is fundamental for understanding the challenges, opportunities, and risks involved in capital allocation and financing growth. Merely holding production flat, however, is not an option for most independent E&Ps. As public companies, their mission is to grow and the target capital market for these companies is institu-tional growth investors, who expect management to deliver growth at an annual rate of 20% or more. Yet, the silent thief of depletion works silently and persistently against this objective. WHAT IS A GROWTH COMPANY?EnerCom maintains a database containing more than 40 quarters of comprehensive operating, financial, and statistical data on more than 200 companies listed on North American, European and Asian stock markets. We perform analysis and benchmarking for clients, comparing quarterly annual and basin results against peer groups. Our hypothesis and conclusions in this paper are supported by this database and our insight gained from observations and discussions with executives, field personnel, investors, and analysts over the previous 22 years. If growth is the mandate from the investment community to most independents, then how much growth is enough to qualify as a growth company? In response to questions from our clients, we researched the answer using data sourced from EnerComs US E&P database. Figure 1 plots three-year Debt-Adjusted Production Growth per Share, a metric that compensates nominal production growth for changes in capital structure, on the x-axis against three-year share price appreciation on the y-axis. We used the three-year period ended Dec. 31, 2013 in order to provide a long-term perspective on growth, and during a time when the market could be considered relatively efficient having a duration long enough to dampen any large swings in commodity prices.The analysis includes 23 US independent E&Ps for which we had complete data. We observed a strong relationship between debt-adjusted production growth per share and long-term share price appreciation, as evidenced by the 0.7741 R-squared value. We removed companies with interna-tional operations and those with share price changes that were driven primarily by company-specific catalysts having little to do with longer-term operational performance. Had the sample been expanded to include those companies, the R-squared statistic would have been 0.1879. As expected, the market sold off shares of companies that ex-perienced a decline in production, and in general bid-up the shares of those demonstrating a track record of delivering consistent growth. Based on our analysis, we estimate that the growth com-pany effect begins to kick-in when annual debt-adjusted production growth reaches 20% or more. THE INTENSE THIRST FOR CAPITALIf the growth company threshold is approximately 20% for debt-ad-justed production growth, then the question becomes what is the financing required to achieve that threshold and what is a companys 1504ogfj_20 20 3/31/15 3:25 PM1504ogfj_21 21 3/31/15 3:25 PM22WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015F4:LEVERAGE AND EQUITY PRICE CHANGES(11/24/2014 - 12/3/2014)0.00%5.00%10.00%15.00%20.00%25.00%30.00%35.00%Above median debtBelow median debtLarge-cap Mid-cap Small-capAvg. change in equity prices11.78% 11.78%22.32%31.64%5.95%12.95%23.31%F5:E&P SHARE PRICE PERFORMANCE(PERIODS ENDING 1/30/2015)Below median debtAbove median debtWeek YTD 6-MonthsShare price % change10.00%0.00%10.00%20.00%30.00%40.00%50.00%60.00%70.00%0.5%1.8%34.5%0.4%14.6%66.5%ability to grow production organically? We tracked the Asset Intensity of 74 E&P companies from EnerComs US E&P database. Asset Intensity is the percentage of cash flow required to keep production flat, and we measure it by dividing the product of production and three-year finding and development costs by cash flow from operations, on a trailing 12-month (TTM) basis. An Asset Intensity value of less than 100% implies that a company is generating free cash flow in excess of its base decline, which can be reinvested back into organic growth. A value greater than 100% indicates a company is reliant on outside capital just to hold production on par with current levels.At Sept. 30, 2014, the average Asset Intensity for the group was 105%, although skewed higher by a few companies, but indicating that most independents were capable of funding at least a portion of their capital plans with internally generated cash flow. However, even though 64 of the 74 companies in our sample posted Asset Intensity scores less than 100%, they still had to outspend cash flow to achieve their production growth goals. For example, of the 74 independents in our analysis, only 13 posted positive FCF for the trailing 12 months ended Sept. 30, 2014. Simply put, growth company management teams are reliant on outside capital to fund growth plans and have had to dip into the river of capital from time to time. RAISING CAPITAL For management teams at public companies, the river of capital they can tap into includes both equity and debt, while private operators are generally dependent on some form of debt, usually secured by their proved reserves. Over the past five years, US and Canadian E&Ps have raised more than $349 billion in capital from IPOs, secondary equity offerings and debt, as illustrated in Figure 2, which shows the proportion of capital raised by type from 2010 through year-end 2014. By far, debt has been the most popular type of capital for E&P companies to raise. There are several good reasons to employ debt rather than equity, including:Its non-dilutive to share count and the outflow of cash in the form of interest payments is deductible; Reduces the weighted average cost of capital as debt is generally less expensive than equity; The holders of the debt capital instrument are senior to the equity holders and will tend to hold the debt longer; andIts easier to raise as it provides a steady state flow of cash to the holders of the note.Of note is that in 2014, secondary equity offerings surged to 39% of total capital raised, as compared to the average of 23% in the previous four years. We anticipate the increase was due to a variety of factors, including issuing equity for acquisitions and de-leveraging balance sheets.

CAPITAL STRUCTURE EFFECTSIf debt has been the most popular form of capital to raise, then how much leverage do independent E&Ps have? Figure 3 plots net debt to EBITDA for the trailing 12 months ended Sept. 30, 2014 from highest, or most leveraged, on the left to least leveraged on the right for 74 independents in our US E&P universe. The median Net Debt to EBITDA on a TTM basis as of Sept. 30, 2014 for the companies in the group, denoted by the red horizontal line, was 2.0x with values ranging from a low of -3.2x to a high of 20.0x. The gold bars represent those companies operating primarily in resource plays, such as the Eagle Ford shale play of South Texas, the Bakken and Three Forks plays of the Williston Basin, the Mar-cellus and Utica natural gas shale plays, and the Permian Basin of West Texas. We find that the majority of the resource players have below-average leverage, largely the result of high-quality assets that generate strong cash flows, above-average returns, and profitability, all of which combine to reduce the need for external financing. ALLOCATING CAPITAL TO GROWTHIf companies are riding on a river of capital driven by commodity prices, then capital structure plays a role in how high they may sit in the water. A highly levered company sits lower in the water, at greater risk and less maneuverable when markets get turbulent. If a team chooses to put more capital to work by levering-up the balance sheet to accelerate growth and earnings, then we should 1504ogfj_22 22 3/31/15 3:25 PMAPRIL 2015OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM23F6:IRR FOR DRILLING AT THREE PRICE DECKSHaynesvilleMarcellusPermianBasinEagle FordFayettevilleWoodfordBakkenBarnettInternal rate of return (IRR)51.00%48.90%40.30%43.40%11.00%2.60%29.30%18.20% 6.10%24.00%14.70% 3.90%19.00%11.50% 7.60%12.00%11.50%8.60% 8.00% 7.30% 5.20% 8.00% 7.10% 4.50%60.00%50.00%40.00%30.00%20.00%10.00%0.00%10.00%Aug-2014 ($3.89/MMbtu, $95.57/bbl)Nov-2014 ($3.81/MMbtu, $74.34/bbl)Dec-2014 ($3.50/MMbtu, $50.00/bbl)Note: Chart assumes no change in drilling costs F7:WELL COST SENSITIVITY$7,000$7,000$7,000HaynesvilleMarcellusPermianEagle FordFayettevilleWoodfordBakkenBarnett$10,000$9,000$8,000$7,000$6,000$5,000$4,000$3,000$2,000$1,000$0Current well cost 20% IRR ($3.81/MMbtu, $74.34/bbl)20% IRR ($3.50/MMbtu, $50.00/bbl)Well cost (thousands)$9,100$5,900$5,211$69,00$6,550$4,105$7,500$6,675$3,617$2,500$1,890$1,595$4,000$2,950$2,570$9,000$6,650$3,020$3,000$1,630$1,423expect companies with higher debt levels to post above-average production growth rates.To test this hypothesis, we analyzed a subset of 74 companies in our US E&P universe comparing their debt, as measured by Net Debt to EBITDA for the TTM ended September 30, 2014, to year-over-year production growth rates with the Median being 2.0x.It is telling that the companies with above-median leverage grew production during the analysis perod, on average, at 25%, as compared to 42% for companies with leverage below the median. At first, this observation is counter-intuitive, and we recognize that there may be a chicken and egg effect here, in the sense that several of the above-average leveraged companies are non-resource players, but not all. The above median group also includes some companies that have divested assets to reduce debt.The E&P companies with Net Debt to EBITDA below the 2.0x median include resource players drilling high-quality assets, including the Bakken/Three Forks shale oil play, the Marcellus and Utica shale gas plays, the Eagle Ford shale play in South Texas, the horizontal Niobrara play in the Colorado D-J Basin and the multi-pay, multi-play Permian Basin of West Texas.A key observation is that asset quality appearstodrivecapitalstructure,not vice-versa. EQUITY MARKET REACTIONS TO CAPITAL STRUCTURE The equity markets reaction to companies with above-median leverage has been de-finitive. The chart below looks at the aver-age change in equity prices for above and below median debt E&P companies in reaction to Saudi Arabias Thanksgiving Day Surprise decision not to cut produc-tion to support world crude oil prices in 2014.Figure 4 illustrates the average share declines from Thanksgiving Day to the market close the following Monday, Dec. 3, 2014.Shares of independents with leverage above the median lost more value than their more lightly levered peers in every market capitalization group. Figure 5 takes a more recent, and longer-term view of the same group. For the six months ended Jan. 30, 2014, the equity prices of E&Ps with debt to EBITDA greater than the 2.0x me-dian suffered substantially more than those with below median leverage.Putting it in perspective, companies with net debt to EBITDA above the median of 2.0x experienced share price declines almost twice as severe as those with below median debt. In our view, there are several reasonsfortheselloffofleveraged companies:Greater financial risk, and in some cas-es, perceived financial distress as cash flows compressed by weakened com-modity prices put the ability to service debt in doubt;Growth expectations reduced lower than those of companies with low, or no, debt, as interest payments eat into shrinking discretionary cash flow; andIntheeventofadefault,lessequity availablefordistributionto shareholders.Make no mistake that companies with below-average leverage have experienced a bumpy ride, but they have been able to navigate more effectively through the rap-idsofthedynamiccommodityprice environment. 1504ogfj_23 23 3/31/15 3:25 PM24WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015F8:MORE DEBT = BIGGER CAPEX CUT10.0x8.0x6.0x4.0x2.0x0.0x2.0x4.0x6.0x80%60%40%20%0%20%40%60%Total debt / EBITDA (TTM 9/30/2014)2015 Capital budget change from 2014E%Change CapEx Debt/EBITDA Average =3.2xAverage = 1.7x57%51%50%49%41%41%39%37%37%33%28%22%16%14%9%3.4x2.1x 2.1x2.3x2.8x2.2x6.7x1.8x2.2x1.1x 1.1x1.9x0.9x2.5x1.2x1.8xA B C D E F G H I J K L M N O P2%CAPITAL ALLOCATION WELL ECONOMICS E&P equity prices have fallen along with commodity prices, and so have the eco-nomics of drilling in the US. The Figure 6 illustrates the internal rates of return (IRR) for drilling in eight of Americas known re-source plays at three different price decks (assuming no change do drilling costs). In August 2014 with the near-month futures price for WTI at $95.57 per barrel and natural gas of $3.89 per MMbtu, most US oil plays generated strong returns above the costs of capital for most E&P compa-nies. As prices deteriorated into the fall, so did returns on drilling, as illustrated by the drop in IRRs at the $74.34 per barrel price level. At prevailing rates of $50 per barrel, the economics of drilling in nearly every resource play in America are stressed below the prevailing cost of capital. As previously noted, the industrys re-sponse to the realities of the new price environment and severely deteriorated well economics has been nothing short of dra-matic. Operators moved quickly to stand down rigs across the North American oil patch, dropping the Baker Hughes rig count to levels not seen since the third quarter of 2010.Of course, there are two sides to drilling economics commodity prices and costs. At prevailing commodity prices and capital expenditure levels, the economics of drilling in most plays do not merit the allocation of additional capital. So, we analyzed how far drilling and completion costs must decline to induce operators to stand-up rigs and drill.Figure 7 illustrates the drilling and completion costs for the same resource plays noted above required to generate a 20% IRR. Keen observers will note that the largest drops in required drilling and completion costs occur in oil plays. Our models estimate that capital costs for drilling and completion have to fall 41%, 52% and 66% in the Permian Basin, Eagle Ford Shale and Bakken oil shale plays, respectively. We note that this analysis is based on public company data, represents a broad range of data points and is not necessarily representative of results for an individual company or a specific well. In other words, your mileage may vary, depending on how the data is used and we update this analysis as market conditions change. CAPITAL STRUCTURED TO ENDURE When the down cycle comes, an E&P companys capital structure and its ability to endure the cycle take center stage. One of the unique features of the oil and gas business is that the value of an E&P companys most important assets oil and gas reserves fluctuate daily with commodity prices, but the amount of debt on the balance sheet stays the same and must be repaid in full. To cope with compressed margins, lower free cash flow and wounded drilling economics, operators have cut capital spending in 2015 from 2014 levels. Figure 8 illustrates announced 2015 capital budgets compared to estimated 2014 spending levels (either based on guidance or analyst estimates). From left to right in Figure 8, companies are ranked by largest capital expenditure decline to the lowest (growth), as of Sept. 30, 2014 and proforma for material capital raises before year-end. The impact of leverage is apparent. Companies with announced capital budget 1504ogfj_24 24 3/31/15 3:26 PMMember FINRA. Investments in oil and gas properties involve substantial risk including the possible loss of principal. These risks include commodity price uctuations and unforeseen events that may afect oil and gas property values.CONTINUOUS ONLINE AUCTION RAPID-CYCLE SEALED BID SALES NEGOTIATED SALES STATE LEASE SALESThe Marketplace is ready when you are.www.energynet.com877-351-4488DiscoverThe MarketplaceEnergyNet helps people sell oil and gas properties. We provide a steady stream of opportunities for buyers to evaluate.We specialize in the sale of producing elds, operated working interests, non-operated working interests, overrides, royalty interests, non-producing minerals, non-producing leasehold, and state leases.We facilitate sealed bid, negotiated, private and auction transactions, and specialize in deals valued from $100K up to $50MM.EnergyNets advantages are:1.our broad and frequent access to buyers in the market 18,000 buyers and growing,2. our high 84% sales close rate, and3. our speedy sales process.We have a platform and marketing process that consistently works. Visit www.energynet.com or call 877-351-4488. Contact us today, and come discover The Marketplace!1504ogfj_25 25 3/31/15 3:26 PM26WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015F9:IMPACT OF DILUTION EFFECT ON E&P EQUITIES23%8%4%2%3%3%20%19.63%22.44%18.55%32.68%6.78% 6.88%28.53%-30%-20%-10%0%10%20%30%40%A B C D E F G6-Day market reaction% Dilutioncuts greater than 40% have debt to EBITDA ratios of 3.2x on average, as compared to 1.7x for those E&P companies with announced reductions of less than 40% and in two cases even a slight uptick in spending.Even with dramatic reductions in capital expenditures, operators still report they will grow production in 2015. Wells drilled in 2014 but not yet completed are likely to be placed on production in the first half of the year, while those wells that produced a partial year in 2014 will show a full year of production in 2015. Combined, these factors will drive production increases, although the rate of growth should decline. We also note that at current oil price levels, it is still profitable to produce in most major oil plays. The average operating expense and overhead costs for the 87 companies in the US E&P subset of our database was $22.37 per barrel of oil equivalent at Sept. 30, 2014. Even at $45 per barrel, most operators are generating positive cash flow from operations. Lets talk about the decision to allocate capital to drill new wells versus producing wells, given profitable operations. Calculating the go-forward internal rate of return on an es-tablished, producing well (after classifying the initial capital for drilling and completion as a sunk cost) is quite different, or superior, to that of drilling a new well with flush pro-duction. Therefore, producers are not really incentivized to shut-in production from profitable wells. Rather, they are highly incentivized to keep the values open and invest capital to enhance or maintain production and improve operational efficiencies, because companies have G&A burden (overhead), financing burden (interest and principle), and stock market burden (stock price) to cover. THE BONDS THAT TIEInvestors are very aware of the new microeconomic realities imposed on E&P companies by the macroeconomic environment. Not only have equity valuations fallen, but refinancing debt for many E&Ps has become more expensive.From 2010 through year-end 2014, the yields on higher-quality bonds have steadily declined, along with the general trend in interest rates. In the fourth quarter, however, yields on lower quality paper having an S&P rating of B or CCC, skyrocketed. A sample of CCC rated bonds issued by independent E&Ps rose to approximately 15% at year-end 2014, up from about 7.0% only two months previous. The river of capital continues to flow, and we note that approximately $3.4 billion of corporate bonds for independents reach maturity during 2015, and lower quality credits may find refinancing substantially more expensive in todays market than they may have anticipated. BORROWING BASE REDETERMINATIONSRevolving credit facilities are another cap-ital source, and as spring approaches, CFOs and bankers alike are thinking about this years first round of borrowing base rede-terminations. On average, 50 E&P compa-nies in EnerComs US E&P database have drawn down only 24% of their availability. However, that average masks the fact that severalofcompaniesareclosetofully drawn. Depending on their year-end 2014 reserves report and the lending bank price deck, they could find themselves in the difficult position of having to cut capital spending further, sell their hedge book to pay down a reduced borrowing base, and/or renegotiate covenants.THE STRONG GET STRONGER TAPPING THE EQUITY MARKETS Although we cannot avoid covering some of the negative impacts of the current down cycle,thereissomesunlightshining through the storm clouds. Several indepen-dents recently have tapped equity markets toshore-uptheirbalancesheetsand strengthen their competitive positions, and found a warm reception from investors.We evaluated eight secondary equity deals that collectively raised $3.95 billion of fresh capital for their issuers. All of the announcementsindicatedthatamong other uses, the proceeds would be used to pay down outstanding indebtedness. In addition, several of the new equity issuers mentioned they planned to use their revi-talized financial strength to take advantage of the current cycle and consider acquisi-tion opportunities.Ordinarily, we would expect an equity offering announcement to result in a re-duction in share price, to account for the dilution of ownership resulting from the additional shares, at least in the short run. Apparently, these are not ordinary times, as we did not observe share price declines in proportion to the dilution impact, and in a few cases we observed the opposite. Figure 9 compares the six-day equity price change for the independents in our analysis to the dilution percentage, as mea-sured by the number of new shares divided by existing shares outstanding at Sept. 30, 1504ogfj_26 26 3/31/15 3:26 PMAPRIL 2015OIL & GAS FINANCIAL JOURNAL|WWW.OGFJ.COM272014. As a rule of thumb we use a six-day period covering the three days before and after an announcement, to measure the impact of news on a companys share price. This duration helps us control for market trends outside the control of management, such as commodity prices and other noise, and events occurring outside the impact period. The companies are ranked left to right by positive to negative share price change. The average equity dilution for the secondary offerings we an-alyzed was 19%, ranging from a low of 6.8% to a high of 33%. Somewhat counter-intuitively, the average six-day equity market reaction to the equity raises was a positive 1%, ranging from a high of positive 23% to a low of negative 20%. For those companies perceived to have strong operations, expan-sion opportunities and good operational performance, investors appeared to view the new equity capital as a catalyst for getting stronger.It is important to note that nothing in our business is static. Since we last looked at the equity issuers in early March, the shares of all E&P companies have declined along with further commodity price weakness. The change in share prices illustrates the impact of further declines in commodity prices since the equity offerings were closed. If we needed any reminder, no matter how good a management team or its assets, the prices of oil and gas company stocks rise and fall on the global tide of commodity prices. NEARING THEBOTTOM? There may be several reasons for the market not selling off the shares of companies raising equity in the current environment to several factors, including:At this point in the cycle, those investors who wanted to trim or eliminate their exposure to oil and gas names have already done so. In other words, the panic and fear money is gone. Short sellers have made their money, and after a 50%+ decline in oil and gas valuations, they may have less interest in betting on additional weakness. Bargain hunters abound. As we reported at EnerComs confer-ence in San Francisco in February, 76% of respondents to our survey of the West Coast buy-side indicated they were in bargain hunting mode, looking for opportunities to stock-up on their favorite names at discount prices, providing willing buyers to those looking to rotate out of the sector. Combined, the above factors may have helped to create support for oil stocks before the most recent dip in oil prices this month, and no one minimizes the potential for commodity prices to go lower before they go higher. However, we do note a split on broad investor sentiment on the future direction of oil and gas prices. For example, respondents to our West Coast buy-side survey conducted in February 2015 were nearly evenly divided on oil prices. 52% of respondents expected oil prices to rebound to the $70 to $85 per barrel range and 43% expected continued trading in the $40 to $50 per barrel range. Only 5% believed prices would fall from prevailing levels. It bears mentioning that no one antici-pated a return to $100 oil in the next 12 months.With 95% of the market believing oil prices are at or near a bottom, oil and gas equity investors decided now was the time to put more equity into their favorite names. We anticipate more companies will consider tapping the equity river of capital in 2015. OIL AND GAS IS (STILL) A SUNRISE INDUSTRYWhen the sea changes, investors want a steady hand on the helm of the corporate ship. Those teams with experience managing through the cycles have an edge, a portfolio of high-quality assets certainly helps make things easier and a conservative capital structure helps improve a teams ability to navigate turbulent markets. Over the past 14 quarters, public E&Ps have raised more than $100 billion in new equity and debt capital, and if past is prologue, the best future per-formers will be those who have been able to manage the capital cycle to generate profitable growth and strategic advantage. We are mindful that within every cycle are planted the seeds of its own destruction. Although the down cycle initiated by the Saudi grab for market share has brought with it much upheaval to much of the rest of the worlds oil producing nations, including America, we note that the longer term trends appear to be working towards a rebalancing of supply and demand in the future.As middle classes in developing nations grow and prosper, we anticipate that they will want to live a more energy-intensive lifestyle, which includes central air conditioning, maybe central heating too, and they will want a diet consisting of more protein and drive or use more public transportation. Simply put, a growing number of humanity will be living more materially prosperous and healthier lifestyles that necessarily consume more energy, and oil and natural gas are simply the most cost-efficient energy sources to deliver on that need. In our view, oil and gas remains a sunrise industry, and this cycle, too, shall pass like all the others. The market will eventually find its equilibrium, and the river of capital will continue to flow into and through this current down cycle. Those management teams able to adapt to changing circumstances and wisely conserve, raise, allocate, and generate capital are those most likely to profit from the current down cycle and see the dawn of the next up cycle sooner than others. ABOUT THE AUTHORJames Constas, managing director at EnerCom Inc., has more than 23 years of professional experience, primarily in oil and gas, in consulting, management, marketing, finance, economics and investor relations. He received his BS in International Management from Arizona State University and an MBA in Finance from the University of Denver. He is a member of the National Association of Petroleum Investment Analysts.Since 2008, a river of capital has flowed into the upstream sector of the North American oil and gas industry. One large boulder that fell into this metaphorical river, however, was OPECs 2014 Thanksgiving Day Turkey Surprise in which swingproducerSaudiArabiadecidedagainstcutting crude production, even symbolically, to defend oil prices.1504ogfj_27 27 3/31/15 3:26 PM28WWW.OGFJ.COM|OIL & GAS FINANCIAL JOURNALAPRIL 2015SINCE JULY 2014 the crude oil price has more or less halved. As a consequence, we expect the oil and gas industry to cut its upstream CAPEX budgets by an estimated 21% to US$538 billion in2015comparedwiththerecordhighofUS$679billionin 2014.Companiesofferingtheirservicesandproductstotheoil and gas industry the oil services sector are facing less de-mand from operators on the one hand and increased capacity bytheirownsectorontheother,resultingindeteriorating market conditions.Taking into account higher unconventional oil production inNorthAmericain2015andsurpluscapacitybytheOPEC countries,webelievethattheBrentoilpricewillbearound US$50 per barrel in both 2015 and 2016. However, lower CAPEX spending, particularly in North America, will result in lower oil production as of 2016 2017. At the same time, the worldwide demand for oil and gas will increase structurally. As a result, we expect that oil prices will gradually recover to US$95 in 2020, leading to higher CAPEX spending again. The latter is necessary to raise oil and gas production in the relatively more expensive (deepwater) offshore fields. The increasing importance of off-shoreoilandgasproductionincombinationwithrecently announcedcostsavingmeasureswillresultinourviewina recovery of the oil services market as of 2018.NEW FIELDS NEEDED TO MEET DEMAND According to the International Energy Agencys World Energy Outlook 2040, global demand for oil and gas will increase by a CAGR of 0.5% and 1.6%, respectively, over the period 2012-2040. Inabsolutenumbers,oilandgasconsumptionwillgoupby 14% and 55%, respectively. Regarding oil, the forecasted increase seems low, but we have totakeintoaccountthedepletionofexistingproducingoil fields. The IEA uses 4% as an average depletion rate, i.e. the oil production of an existing field goes down by 4% every year. To put this number in perspective, global oil production was about 91 million barrels per day (b/p/d) in 2014. The IEA expects a demandof102millionbpdin2040,ofwhich29millionbpd wouldcomefromexistingfields,and73millionb/p/dfrom new fields.Regarding unconventional oil production in North America, the depletion rate is not 4% per annum, but on average 85% in the first two years. As a result, drilling of new wells in North Americahastoremainhighjusttomaintainproduction levels.OIL PRICES UNDER PRESSURE IN 2015 AND 2016 Although the Brent oil price recently has recovered to US$60, we expect, on average, an oil price of US$50 in both 2015 and 2016.Themainreasonistheunconventionaloilproduction growth in North America (2015: +0.7 million bpd), which nearly equalsthepredictedriseofglobalconsumption.Inaddition, theOPECcountriesdohavespareproductioncapacity.Fur-thermore, several countries, notably Libya and Iran, produce significantlylessthantheirnormalproductionlevelsdueto civil unrest and sanctions.With current high oil stock levels, we believe the chance of over-supply in the short term is higher than the chance of undersupply. However, we believe that lower CAPEX spending by the oil and gas industry in the short term, particularly in North America, will lead to pressure on production rates in the longer term. With rising de-mand for oil in the coming years, pressure on production in our view will lead to a recovery of the oil price as of 2017 onwards.CAPEX DOWN BY AN ESTIMATED 21% IN 2015Between 2000 and 2013 the global oil & gas industrys CAPEX increased by a CAGR of 14.8%. According to Barclays, CAPEX rose to a new record of US$679 billion in 2014. CAPEX increased strongly due to (i) growth of global oil and gas consumption, (ii) underinvestments in the 1990s, (iii) an increasing shift from onshore to offshore production, which is relatively more expen-sive, and (iv) cost inflation. The latter was caused by a shortage of staff and equipment, but also due to increased local content requirements.In early 2014, the oil majors (ExxonMobil, Shell, BP, Chevron, ConocoPhillips,Total,andENI)alreadyannouncedCAPEX budget cuts for 2014. The fall of the oil price since July 2014 has alsoforcedotheroilandgascompaniestocuttheirCAPEX budgets for 2015. Particularly unconventional oil and gas pro-ducing companies in North America have announced CAPEX budget cuts of tens of percentage points. Furthermore, the oil majors stepped up their budget cuts even further.To sum up, we expect the oil and gas industry will lower its CAPEX spending by 21% to US$538 billion in 2015, followed by a further drop of 5% in 2016. As a result, oil production growth will be limited or even become negative in 2017, tightening the supply/demand balance and leading to the recovery of the oil price. Therefore, the oil and gas industry will raise its upstream CAPEX budgets again as of 2017, leading to a new record high in 2020.OFFSHORE PRODUCTION GROWTHEXCEEDS INCREASE OF ONSHOREOil and gas production at offshore oil and gas fie