CreditWeek. Oil And Gas Companies. CreditMatters Multimedia Edition. Commodity Prices Aren t The Only Credit Factor.

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1 CreditMatters Multimedia Edition CreditWeek The Global Authority On Credit Quality December 14, 2011 Special Report Oil And Gas Companies Commodity Prices Aren t The Only Credit Factor Sovereign And Bank Rating Linkages Europe s Economy: Back In Recession Eurozone Trade Balances Weigh On Growth

2 contents December 14, 2011 Volume 31, No. 47 COVER IMAGE: CORBIS 4 Special Report Oil And Gas Companies: Commodity Prices Aren t The Only Credit Factor By Thomas Watters, New York With a barrel of crude oil bouncing around $100 and natural gas prices mired in a long slump, it s easy to take a simplistic view of the disparate fortunes of companies in these sectors. But a complexity of factors from spending plans to refining margins to mergers and acquisitions may say more about the environments in which these borrowers operate than the mere price of the commodities they produce. 7 High Oil Prices Buoy Prospects For North American Contract Drillers Credit Quality By Lawrence Wilkinson, New York North American land-based drilling companies saw their balance sheets improve in 2011 as rig counts rose. Meanwhile, offshore drillers faced the third successive year of declines in profitability and credit protection measures due to rig oversupply, equipment upgrade and certification costs, and debt-financed growth activities. The credit profiles of land-based drillers should keep strengthening, with modest improvement from their offshore counterparts. 9 Is Natural Gas Drilling Economic At Current Prices? By Carin Dehne-Kiley, New York Despite a 75% drop in U.S. natural gas prices since mid- 2008, companies continue to drill. Exploration and production companies aren t covering their total natural gas costs with unhedged natural gas revenues. And we don t believe they re generating returns above their cost of capital with dry natural gas projects. Companies can drill uneconomic natural gas wells only for so long before their financial risk profiles and credit ratings begin to suffer. 13 Why U.S. Refiners In The Midwest And Rockies Should Outperform Peers In 2012 By Paul B. Harvey, New York U.S. refiners operating in the Midwest and Rocky Mountain regions are likely to continue to outperform refiners in U.S. coastal regions in Midwest and Rocky Mountain refiners should continue to benefit from lower crude oil costs and limited imports of refined products. By contrast, refiners on the East, West, and Gulf coasts tend to use pricier, offshore, or imported crude oil and at the same time face competition from imported refined products. 16 Big Spenders: Latin America s National Oil Companies, Petrobras And PEMEX By Paula Martins, São Paulo If they were typical public companies, Petroleo Brasileiro S.A.-Petrobras and Petroleos Mexicanos might be courting criticism with their aggressive plans to spend as much as $340 billion to expand oil exploration and production. Risk is relative, however, for the two largest national oil and gas companies in Latin America. Their status as government-related entities makes them a key ingredient in Brazil s and Mexico s recipe for stimulating growth. 2

3 Multimedia 5 Teleconference Replay: Hot Topics in the Oil & Gas Industry 9 Video: Why U.S. Natural Gas Companies Continue To Drill Natural gas spot prices are hovering around $3 per thousand cubic foot (mcf). However, the cost to find, develop, and produce the gas runs at about $4.45 per mcf. So why do companies continue to drill if they can't cover their costs? In this CreditMatters TV segment, Standard & Poor s Associate Director Carin Dehne-Kiley explains what's behind these companies' thinking. Topics include the most profitable regions, rig counts, hedging, acreage, and what the current practice could mean for companies' credit profiles. 7 Video: High Oil Prices Fuel Prospects For North American Contract Drillers Overall, land-based contract drillers have enjoyed a profitable But why haven't offshore drilling companies fared equally well? In this CreditMatters TV segment, Standard & Poor s Director Larry Wilkinson examines the state of contract drillers. Topics include our expectations for landbased contract drillers, why offshore drilling has struggled, and what we expect for credit quality in Video: Why U.S. Refiners In The Midwest And Rocky Mountains Will Outperform Peers In 2012 U.S. refiners operating in the Midwest (PADD II) and Rocky Mountain (PADD IV) markets are likely to continue outperforming refiners in coastal regions next year. But will the Seaway pipeline reversal affect their success? In this CreditMatters TV segment, Standard & Poor s Director Paul Harvey discusses how the Seaway pipeline announcement has changed PADD II and PADD IV. Topics include why we still expect the refiners to perform well, their sustainability, and the potential rating implications for the industry. 16 Podcast: What s Fueling The Investment Plans Of PEMEX And Petrobras In this podcast, Standard & Poor s credit analysts Paula Martins and Fabiola Ortiz discuss the ambitious exploration and production plans of Petroleos Brazil and Petroleos Mexicanos. Topics include why these companies are increasing their investments, the main opportunities and challenges, and the potential ratings implications as a result of higher investments. 16 Podcast: (Portugese) Por Quê A Pemex E Petrobras Vêm Aumentando Seus Investimentos Neste podcast, as analistas da Standard & Poor s, Paula Martins discutem os ambiciosos planos de exploração e produção da Petrobras e da Pemex, suas principais oportunidades e desafios e como esses grandes investimentos podem afetar os ratings destas empresas. 16 Podcast: (Spanish) Qué Está Impulsando Los Planes De Inversión De Pemex Y Petrobras En este podcast, la analista de Standard & Poor s, Fabiola Ortiz habla sobre los ambiciosos planes de exploración y producción de Petróleos Mexicanos y Petroleo Brasilerio S.A. Los temas sobre los que comenta incluyen las razones por las que ambas petroleras están aumentando sus inversiones y sus principales oportunidades y desafíos, así como las potenciales implicaciones que las mayores inversiones podrían tener en sus calificaciones. Related Materials Click through these articles to view downloadable PDFs/Podcast Bargain Hunting: How M&A Affects North American Oil And Gas Companies Credit Quality By Michelle Dathorne Podcast: North American Oil And Gas Companies: How M&A Affects Credit Quality Ratings For U.S. Oil And Gas Are Stable, Despite Economic Woes By Thomas Watters Key Credit Factors: Criteria For Rating The Global Oil Refining Industry By Scott Sprinzen and Thomas Watters Natural Gas Price Assumptions for 2012 And 2013 Revised; 2014 Oil And Natural Gas Assumptions Added By Thomas Watters Standard & Poor s CreditWeek December 14,

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5 Oil And Gas Companies Commodity Prices Aren t The Only Credit Factor With a barrel of crude oil bouncing around $100 and natural gas prices mired in a long slump, it s easy to take a simplistic view of the disparate fortunes of companies in these sectors. But a complexity of factors from spending plans to refining margins to mergers and acquisitions may say more about the environments in which these borrowers operate than the mere price of the commodities they produce. Standard & Poor s CreditWeek December 14,

6 features special report Naturally, global integrated exploration and production (E&P) companies that concentrate on oil are benefiting greatly from sustained high crude prices, as are the service providers that support drilling and production. And just as clearly, the sharp decline in the price of natural gas since mid-2008 has created certain hurdles for E&P companies focused on that sector. At the same time, Standard & Poor s Ratings Services believes this view only begins to describe the opportunities and challenges in the oil and gas industry. We expect credit quality for the U.S. oil and gas sector to remain relatively stable into 2012, despite a still-fragile economic recovery. For example, investment grade (rated BBB- or higher), integrated North American oil and gas companies continue to adjust their portfolios of assets by selling low-value, low-return properties or businesses (such as refineries). As a result, borrowers with broadly diversified operations can use the proceeds to finance investments in other business units or to achieve higher internal rates of return. Meanwhile, companies with the operational and financial flexibility to capitalize on industry cycles are making opportunistic purchases at reasonable prices. Moreover, some smaller, speculative-grade (rated BB+ or lower) firms are also taking advantage of favorable capital markets and interest rates to increase their oil and gas production through acquisitions. Companies with some financial cushion or a willingness to use both equity and debt to finance acquisitions will suffer fewer negative effects on their creditworthiness than those with comparatively weak liquidity and high levels of debt, in our view. Meanwhile, natural gas E&P companies may not be sufficiently covering their all-in costs for natural gas. And we believe companies can only drill uneconomic natural gas wells for so long before suffering damage to their financial risk profiles and, as a result, to their credit ratings. Although many companies are shifting their spending to oil and liquefied natural gas, getting such production running may take longer and cost more than they anticipate. Alternatively, demand for drilling services looks set to remain healthy in Increasing demand from oilfocused players should continue to more than offset declines related to natural gas, benefiting the performance of onshore contract drilling companies. All told, we expect credit quality for the U.S. oil and gas sector to remain relatively stable into 2012, despite a still-fragile economic recovery. We believe that a gradually strengthening economy will help keep oil prices close to $100 a barrel, as well as marginally higher prices for natural gas. Still, our base-case forecast calls for mild economic growth, with real GDP expanding 1.9% next year though we put the chance of slipping back into recession at 35%. High oil prices often translate into consumers spending more on energy and less on discretionary items. This could hurt retailers and other sectors that depend heavily on consumers. As a result, these businesses may lay off workers, which keeps unemployment high and puts an even tighter squeeze on consumers. Still, we believe the price of oil would have to surge to around $150 a barrel to plunge the U.S. back into recession on its own, and we don t expect high oil prices to do significant damage to the recovery. CW For more articles on this topic search RatingsDirect with keyword: Oil and Gas Analytical Contact: Thomas Watters New York (1)

7 High Oil Prices Buoy Prospects For North American Contract Drillers Credit Quality With crude oil averaging above $90 a barrel and exploration and production (E&P) companies demanding more (and more-varied) drilling services, 2011 has been a busy year for North American drilling companies. However, the financial effects in the contract drilling sector have been uneven. Land-based drillers saw their balance sheets improve as rig counts rose. Meanwhile, offshore drillers faced rig oversupply and equipment upgrade and certification costs, which, coupled with debtfinanced growth activities, made 2011 the third successive year of declines in profitability and credit protection measures. Standard & Poor s Ratings Services expects demand for drilling services in 2012 to continue to rise. We believe the credit profiles of land-based drillers will keep strengthening, albeit at a slower pace, and we expect more modest improvement from their offshore counterparts. Land-Based Drillers Continue To Witness A Shift To Oil From Gas Onshore contract drilling companies performance continues to strengthen, with increasing demand from oil-directed plays more than offsetting declines for natural gas. High oil prices have led E&P companies to spend more toward developing acreage in unconventional shale plays, such as the Bakken play in North Dakota and the Eagle Ford and Wolfberry plays in Texas. As a result, as of Nov. 18, 2011, overall oil rig counts had risen over 50% over the same time last year. At the same Overview Rising rig counts have benefited land-based drillers this year. We expect their credit profiles to keep improving in 2012, but at a slower pace than we ve seen this year. High oil prices continue to fuel a shift in exploration and production to oil and away from natural gas. For offshore drillers, we expect rising day rates and utilization to lead to moderately better financial performance in Standard & Poor s CreditWeek December 14,

8 features special report time, weak natural gas prices have resulted in a slight pullback in development of those assets. The number of natural gas-directed rigs has declined by slightly more than 10% compared with the prior year (see chart 1). The net impact of these two trends has been a roughly 20% year-over-year increase in land-based rig counts, to more than 2,000 units (see chart 2). Onshore Drillers Financial Performance Will Likely Keep Improving In 2012 We expect onshore contract drillers credit profiles to continue to improve in 2012, albeit at a slower pace than we ve seen this year. Given the current favorable outlook for oil prices, oil drilling will likely continue to offset declining natural gas rig counts. Drillers will likely see continued strong rig Chart 1 Oil and gas 1,200 1,100 1, Oil Gas utilization and even some further strengthening of day rates in the first half of the year. However, the cost of newly built rigs scheduled for delivery in 2012, coupled with the displacement of some rigs from natural gas basins, will likely limit these gains. For Nabors Industries Inc. (BBB/Stable/ ) and Pioneer Drilling Co. (B/Stable/ ), continued gains in both utilization and day rates along with new rigs and equipment coming on line and charging day rate will likely boost their credit protection measures. However, the higher costs required for upgrades and new fleet additions may temper these improvements somewhat. In the case of Precision Drilling Corp., we believe that the pace of debt-financed rig additions could leave the company challenged to 400 January 2010 May 2010 September 2010 January 2011 May 2011 September 2011 Source: Baker Hughes Inc. Standard & Poor's Chart 2 2,200 2,000 1,800 1,600 1,400 1,200 Rig Count Rig Counts Total onshore and offshore 1,000 Jan April 2010 July 2010 Oct Jan April 2011 July 2011 Oct Source: Baker Hughes Inc. Standard & Poor s preserve credit protection measures at levels consistent for the current rating. Most Offshore Drillers Credit Measures Deteriorated In 2011, But 2012 Looks More Promising Coming off a peak in 2008, offshore contract drillers such as Diamond Offshore Drilling Inc. (A-/Stable/ ), Noble Corp. (BBB+/Stable/ ), Ensco PLC (BBB+/Negative/A-2), and Transocean Inc. (BBB-/Negative/A-3) have seen successive declines in profitability and credit protection measures. While rig oversupply and the resulting erosion in day rates and utilization have played a role, other factors have been influential as well. Post-Macondo safety and equipment standards have resulted in more out-of-service time and greater maintenance expenditures than many issuers expected. Furthermore, a number of offshore drillers have contracted for new rigs or funded acquisitions without equity. The net impact has been a significant erosion of credit quality for many issuers in the sector. Nonetheless, we anticipate moderately better financial performance for offshore contract drillers over the course of Continued strong oil pricing and the resulting E&P demand, a drop in the number of new rigs coming on line, and limited availability of high-specification floating rigs all bode well for these companies. While day rates for floating rigs have stabilized over the last several quarters, day rates for jackup rigs (offshore rigs with retractable legs) have shown sequential improvement. The tightening in overall rig supply will likely boost day rates and utilization for offshore contract drillers in Although there may be pockets of weakness for lower-specification rigs, overall credit quality should improve as the benefits of a tighter market and earnings from recent fleet additions begin to show up in the companies results. CW For more articles on this topic search RatingsDirect with keyword: Drillers Analytical Contacts: Lawrence Wilkinson New York (1) Paul B. Harvey New York (1)

9 Is Natural Gas Drilling Economic At Current Prices? Despite a 75% drop in U.S. natural gas prices since mid-2008, companies continue to drill. The spot price for gas, as measured by the Henry Hub benchmark, has declined to about $3.35 per million Btu (MMBtu) today, from its peak of $13.00 per MMBtu in mid-2008, with the 12-month strip price at about $3.70 per MMBtu. The natural gas-weighted U.S. exploration and production (E&P) companies we rate spent an average of $3.35 per thousand cubic feet equivalent (Mcfe) in the second quarter of 2011 to find, develop, and produce natural gas ($4.45 per Mcfe including interest costs). Based on these numbers, E&P companies are not covering their total natural gas costs with unhedged natural gas revenues. And we don t believe they are generating returns above their cost of capital (10%) with most dry natural gas projects. We believe that companies can drill uneconomic natural gas wells only for so long before their financial risk profiles and, thus their credit ratings, begin to suffer. Recent trends in U.S. drilling activity support our conclusions. Since reaching Overview We don t believe E&P companies are covering their total costs for dry natural gas production with unhedged revenues. Companies are also shifting their capital investments toward oil and NGL drilling. Our ratings on natural gas-focused E&P companies could come under pressure. Standard & Poor s CreditWeek December 14,

10 features special report Chart 1 1,800 1,600 1,400 1,200 1, Oil rigs U.S. Oil And Natural Gas Rig Count a peak of 1,600 in September 2008, the number of rigs actively drilling for natural gas in the U.S. is down 45% to about 865 currently. By contrast, over the same period, the number of rigs drilling for oil in the U.S. nearly tripled to more than 1,100 (see chart 1). And almost every E&P company is shifting capital to oil or natural gas liquids (NGLs) and away from dry natural gas. Even so, many E&P operators say their own gas fields are generating at least a 10% rate of return. We believe most such economic returns are associated with unconventional natural gas shales. Compared with conventional plays, shale reservoirs tend to be more uniform across a broad area and therefore generally carry lower exploration risk. Shale reservoirs have other differences compared with conventional gas fields. Those include higher initial production (IP) rates relative to estimated ultimate recoveries, hyperbolic production decline curves, and long reserve lives. And because most shales are developed using horizontal drilling and fracture stimulation, initial well costs tend to be greater for unconventional than conventional wells. Oil And NGL Assets Produce Better Returns To estimate the internal rates of return (IRR) of major gas shale assets, we used average well data from public sources 1/7/2005 4/7/2005 7/7/ /7/2005 1/7/2006 4/7/2006 7/7/ /7/2006 1/7/2007 4/7/2007 7/7/ /7/2007 1/7/2008 4/7/2008 7/7/ /7/2008 1/7/2009 4/7/2009 7/7/ /7/2009 1/7/2010 4/7/2010 7/7/ /7/2010 1/7/2011 4/7/2011 7/7/ /7/2011 Source: Baker Hughes Inc. Standard & Poor s Natural gas rigs and our commodity price assumptions. Our current natural gas price assumption is $3.75/MMBtu in 2012, $4.00 per MMBtu in 2013, and $4.50 per MMBtu thereafter for the Henry Hub benchmark. Our deck for West Texas Intermediate (WTI) spot crude oil is $80 per barrel (bbl) in 2012 and $70 per bbl thereafter, with the price of NGLs at 55% of WTI. We estimate that at those prices most dry gas assets (those with no associated oil or NGLs) would generate less than a 10% IRR (see chart 2). These include the Woodford shale (Oklahoma), the Piceance Basin (Rockies), the non-core Haynesville/Bossier shales (East Texas), the Eagle Ford dry gas area (South Texas), the Marcellus dry gas area (Northeast Pennsylvania), the Barnett shale (Central Texas), and the Fayetteville shale (Arkansas). The exception to this is the core area of the Haynesville shale in North Louisiana, which we estimate generates around a 12% IRR, because of significantly above-average IP rates. By contrast, gas reserves that include even a small oil or NGL component are generating more than a 10% rate of return, based on our price assumptions. These include the Cana-Woodford shale (Oklahoma), the Marcellus wet gas area (Southwest Pennsylvania), the Eagle Ford oil and liquids rich areas (South Texas), and the Granite Wash formations (Oklahoma/Texas). The latter jumps out with a 22% IRR, but this area carries more exploration risk because it is not a uniform shale. We also included a pure oil asset the Bakken shale in North Dakota in our study. The core Bakken shale generates almost a 40% IRR, which is not surprising given that WTI spot oil prices are trading at over 25x the spot price of natural gas (on an energy equivalent basis). We also evaluated how a 10% change in different variables could affect our IRR calculation (see table and chart 3). Our calculation is most affected by a change in the first year production decline rate, followed by a change in well cost, a well s IP rate, 10

11 and, finally, the first year natural gas price. A shift in production taxes, operating costs, and reductions in estimated ultimate recoveries had less of an effect on the IRR calculation. Natural Gas Production Costs Are Likely To Stay Flat Next Year We estimate that average all-in per-unit costs (for companies with a 75% or more weighting to natural gas) have decreased by about 15% since All-in costs include finding and development (F&D), lifting, production taxes, cash general and administrative (G&A) expense, and interest (including capitalized interest). Because E&P companies do not typically provide cost allocations between oil and natural gas, we looked at companies whose proven reserves are more than 75% natural gas as a proxy for natural gas costs. F&D costs for these companies averaged $1.55 per Mcfe, cash operating costs averaged about $1.80 per Mcfe, and interest costs were $1.10/Mcfe in the second quarter of F&D costs have declined about 15%, on average, since 2008 because of improved drilling techniques and the booking of proved undeveloped locations, while operating costs have remained about flat. Although we believe operators will continue to increase efficiency, especially as they move into full development of the shales, we think more industry activity in the oil and NGL-rich areas will continue to put upward pressure on service costs. Thus, we are assuming flat costs for next year. Based on unhedged revenues for the second quarter of 2011, we estimate the recycle ratio for natural gas drilling averaged 1.5x. We define the recycle ratio as the cash flow generated per Mcfe of natural gas produced divided by per-unit F&D costs. In other words, for every $1 per Mcfe invested, companies generated $1.50 per Mcfe of cash. It s important to recall, however, that Henry Hub natural gas prices averaged $4.36 per MMBtu in the second quarter of 2011; currently they are running at close to $3.35 per MMBtu, with the 12-month strip at $3.70 per MMBtu. Based on our price assumptions of $3.75 per MMBtu in 2012 and assuming all-in Key Assumptions In Internal Rates Of Return Calculation Internal Gross estimated Production Production rates of ultimate % oil/ Gross IP rate First year Well cost Royalty taxes (% cost return (%) recoveries (Bcfe) liquids (Mmcfe/d) decline (%) (mil. $) rate (%) of revenue) ($/Mcfe) Bakken (core) Granite Wash (liquids rich) Bakken (non-core) Eagle Ford (liquids rich) Eagle Ford (oil) Marcellus (liquids rich) Cana-Woodford Haynesville (core) Fayetteville Barnett Marcellus (dry gas) Eagle Ford (dry gas) Haynesville (non-core) N.M Piceance N.M Woodford N.M N.M. Not meaningful. Bcfe Billion cubic feet equivalent. Mcfe Thousand cubic feet equivalent. Mmcfe/d Million cubic feet equivalent per day. Source: Standard & Poor s. Standard & Poor s CreditWeek December 14,

12 features special report Chart 2 (%) Chart 3 (basis points) 1, Bakken core First year decline Granite Wash liquids rich Source: Standard & Poor s. Standard & Poor s Internal Rates of Return* Of Major Shale Plays Well cost Bakken non-core Haynesville core IP rate Marcellus liquids rich Year 1 natural gas price Cana-Woodford costs of $4.45 per Mcfe, we estimate the natural gas recycle ratio would drop below 1x on an unhedged basis next year. A ratio below 1x implies a money-losing project. Why Are Companies Still Drilling For Natural Gas? There are several reasons why E&P companies are still drilling for natural *IRR calculation is based on Henry Hub natural gas prices of $3.75 per MMBtu in 2012, $4 in 2013, and $4.5 thereafter; WTI crude oil prices of $80 per barrel (bbl) for 2012 and $70 per bbl thereafter; and natural gas liquids (NGL) prices of 55% of WTI. Source: Standard & Poor s. Standard & Poor s Impact Of Various Factors On Internal Rates Of Return LT natural gas price Eagle Ford liquids rich Eagle Ford oil Royalty rate Fayetteville Production taxes Barnett Production cost Marcellus dry gas Eagle Ford dry gas Estimated ultimate recoveries gas and, therefore, why U.S. natural gas production continues to increase, including: Hedges they have in place on natural gas production (though hedges are starting to roll off next year); A requirement to drill if they want to hold onto acreage under term leases (although this was mainly a Haynesville shale phenomenon and is starting to wind down); A project s natural gas stream includes some component of oil or NGLs; Joint venture partners who have deeper pockets or more strategic reasons for drilling (such as acquiring shale drilling expertise); A reluctance to announce production cuts because of shareholder response; First movers in certain plays enjoy lower costs (because they acquired acreage before the area became competitive and are likely in the most prolific area of the play); A belief that costs will be lower in the future (because of greater drilling efficiencies or falling costs for oilfield services); and A belief that natural gas prices will be higher in the future. Nevertheless, we believe that companies can drill uneconomic natural gas wells only for so long before their financial risk profiles and thus, their credit ratings, begin to suffer. How long that will take will depend on each company s financial risk profile, including its debt leverage, liquidity, and the amount of natural gas production it has hedged. Although E&P companies are shifting spending to oil and NGLs, starting and increasing production from these oil projects could take longer and cost more than they anticipate, putting additional near-term stress on their financial risk profiles. CW For more articles on this topic search RatingsDirect with keyword: Drilling Analytical Contact: Carin Dehne-Kiley New York (1)

13 Why U.S. Refiners In The Midwest And Rockies Should Outperform Peers In 2012 U.S. refiners operating in the Midwest (PADD II) and Rocky Mountain (PADD IV) regions are likely to continue to outperform refiners in U.S. coastal regions in (In the 1940s, government agencies that no longer exist divided the U.S. into five Petroleum Administration for Defense Districts, or PADDs. In industry parlance, the Midwest and Rockies regions are PADD II and IV. PADDS I, III, and V include refiners on the East, Gulf, and West coasts.) Midwest and Rocky Mountain refiners should continue to benefit from lower crude oil costs and limited imports of refined products. In particular, these refiners are expected to benefit from their use of West Texas Intermediate (WTI) crude oil, which as of Nov. 23 averaged about $8.25 per barrel less than North Sea Brent crude (see chart 1). Moreover, these companies can also refine the rising flow of crude from the Bakken Shale oil field in North Dakota and Montana, which we expect to price at a discount to WTI given the still limited capacity to take production out of the region. We also expect these refiners to benefit from Overview U.S. refiners operating in the Midwest and Rockies have an advantage over their peers in coastal regions because they have access to lower-priced crude. We expect this situation to persist at least through next year. Nevertheless, we expect our ratings on these refiners to remain stable despite their higher margins. Standard & Poor s CreditWeek December 14,

14 features special report the flow of Canadian crude oil grades, particularly discounted heavy grades, into the PADD II and IV regions, which have lower transportation costs. By contrast, refiners on the East, West, and Gulf coasts tend to use pricier, offshore, or imported crude oil, and at the same time face competition from imported refined products both of which hurt their margins relative to refiners in inland regions. That said, we currently don t expect, within the next 12 months, to raise our credit ratings on Midwest and Rockies refining companies such as Flint Hills Resources LLC (A+/Stable/A-1), HollyFrontier Corp. (BB+/Stable/ ), and Marathon Petroleum Corp. (BBB/Stable/A-2) despite their higher profits. Price Gaps Are Not Likely To Widen Considerably To be sure, we currently don t expect the price difference between WTI and Brent to widen much if any in On Nov. 16, 2011, Enbridge Inc. (A-/Stable/ ) and Enterprise Products Partners L.P. (BBB-/Positive/ ) announced that they would reverse flows in the Seaway pipeline and transport crude oil from Cushing, Okla. to Nederland, Texas, reducing the glut at Cushing. As a result of that announcement, the WTI-Brent price difference narrowed by 30% to $9.30/bbl from about $13 per barrel (bbl) (see chart 2). Meanwhile, TransCanada Corp. (A-/Stable/ ) has announced that it will seek permits to construct the southern leg of the Keystone XL pipeline from Chart 1 Future Brent-WTI Crude Price Differential ($/bbl) Brent (left scale) WTI (left scale) Brent-WTI Differential (right scale) Jan March 2012 May 2012 July 2012 Sept Nov Jan March 2013 As of Dec. 5, Source: Bloomberg. Standard & Poor s ($/bbl) Chart 2 Brent-WTI Crude Price Differential ($/bbl) /2/2011 2/2/2011 3/2/2011 4/2/2011 5/2/2011 6/2/2011 7/2/2011 8/2/2011 9/2/ /2/ /2/ /2/2011 As of Dec. 5, Source: Bloomberg. Standard & Poor s

15 Chart 3 Future Brent-WTI Crack Spreads ($/bbl) Brent 3:2:1 WTI 3:2: Jan March 2012 May 2012 July 2012 Sept Nov Jan March 2013 As of Dec. 5, Source: Bloomberg. Standard & Poor s The narrowing of the price differential likely doesn t mean an end to the advantage Midwest and Rockies refiners enjoy. Cushing to the Gulf Coast giving refiners there access to the cheaper crude oil grades. Enbridge expects to reverse Seaway s flows by the second quarter of 2012, expanding shipments to the Gulf to 400,000 barrels per day (bpd) by early 2013 from 150,000 bpd initially. This should allow Gulf Coast refiners to reduce use of imported crude oil grades and benefit from the use of less expensive North American crude grades. The narrowing of the price differential likely doesn t mean an end to the advantage Midwest and Rockies refiners enjoy, however. Based on futures contracts, we expect the Brent-WTI differential to average around $8.25 per barrel in 2012 (see chart 3). Although the Seaway reversal will help alleviate the glut of oil at Cushing refineries, the initial 150,000 bpd capacity falls short of what s needed to end the bottleneck at the Cushing Hub. In addition, we expect production from the Bakken Shale as well as crude from Canadian oil sands to continue to sell at a discount to WTI because of pipeline constraints. A Temporary Cushion For Refiners The strong refining margins we ve seen this year in the Midwest and Rocky Mountain regions are somewhat of an anomaly, and we expect them to continue to weaken over time. In particular, regional advantages could return to more historical levels starting in 2013 as the Seaway and Keystone XL pipelines alleviate the crude oil bottleneck at the Cushing hub. Midwest and Rockies refiners have generated strong cash flows and earnings, but our assessments of their business risk profiles limit the ratings. In general, we would want to see an improved scale of operations, including more markets, and more throughput capacity or number of refineries prior to an upgrade. Nevertheless, generally improved liquidity and financial ratios provide these refiners a buffer against negative rating actions in the next 12 months, in our opinion. Absent a significant drop in margins across all regions such as occurred in 2009 Midwest and Rockies refiners should continue to outpace their peers in coastal regions. CW For more articles on this topic search RatingsDirect with keyword: Refiners Analytical Contact: Paul B. Harvey New York (1) Standard & Poor s CreditWeek December 14,

16 features special report Big Spenders Latin America s National Oil Companies, Petrobras And PEMEX Overview Petrobras and PEMEX, the largest national oil and gas companies in Latin America, are increasing their investments. Both companies want to meet rising domestic demand and find, explore, and develop new reserves. Thanks partly to both companies status as national oil companies, we don t expect to take negative rating actions on them anytime soon, despite their huge investments. If they were typical public companies, Petroleo Brasileiro S.A.-Petrobras (BBB/Stable/ ) and Petroleos Mexicanos (PEMEX; BBB/Stable/ ) might be courting criticism with their aggressive plans to expand oil exploration and production (E&P). Together, they plan to spend as much as $340 billion over the next five years, a theoretically risky figure even though Petrobras is putting its bets on huge oil reserves in Brazil s offshore ultra-deep waters and PEMEX likely will be able to take advantage of Mexico s energy reform legislation of 2008 to increase its production. 16

17 Standard & Poor s CreditWeek December 14,

18 features special report Risk is relative, however, for the two largest national oil and gas companies in Latin America. Their status as government-related entities (GREs) makes them a key ingredient in Brazil s and Mexico s recipe for stimulating growth. This has created an interdependency between companies and governments plans that makes the two companies expansion look feasible and that for now supports our ratings on both. Of course, the two companies also have considerable natural advantages. Brazil (BBB/Stable/A-3) accounts for around one-third of the oil reserves discovered worldwide in the past five years, a large part of which are the pre-salt reserves, located more than 5,000 kilometers underwater and around 300 kilometers off its coast, according to Petrobras business plan. The improvement in Brazil s economy, reflected in our recent upgrade of the (Bil. $) Petrobras PEMEX Petroleos de Venezuela S.A. Sources: Company reports. Standard & Poor s Ecopetrol S.A. (Colombia) sovereign, is attracting high government and private sector investments especially in the oil and gas sector despite global economic uncertainty. Meanwhile, Mexico (BBB/Stable/A-3) has around 50 billion barrels of potential crude oil reserves with which to offset falling production from its maturing fields though 58% of them are in the Gulf of Mexico s deep waters, according to the Ministry of Energy, which would require significant investment for horizontal drilling or other advanced methods. To put things in perspective, Petrobras and PEMEX s capital expenditures are higher than those of Petroleos de Venezuela S.A. (B+/Stable/ ), the other major Latin America oil company, and are comparable to if not higher than those of the largest publicly owned players (see chart). From 2006 to 2010, Petrobras and PEMEX spent about $177 billion Their status as government-related entities makes them a key ingredient in Brazil s and Mexico s recipe for stimulating growth. Oil Companies Adjusted Capital Expenditures Empresa Nacional del Petroleo (Chile) National Gas Company of Trinidad & Tobago Ltd Petroleum Co. of Trinidad & Tobago Ltd. and $63 billion, respectively, especially on E&P activities, while ExxonMobil Corp. (AAA/Stable/A-1+) and BP PLC (A/Stable/A-1) invested around $100 billion each. And the numbers are going up: Petrobras plans to spend $225 billion and PEMEX $114 billion in the next five years. Petrobras Ambitious Plan Is Not Without Its Challenges Petrobras spending plans reflect the company s view that oil will continue to be a significant source of energy, despite growth in biofuels and other renewable sources, in which it is also investing. In 2008, oil accounted for 33% of global energy consumption, and according to market expectations it might still represent 28% by It is also likely, experts say, that developing countries, such as Brazil, will account for most of the rise in demand from now on. Petrobras expects to spend $225 billion in the next five years on 688 projects. This would represent an average of $45 billion per year to meet its ambitious goal of more than doubling its current oil and gas production to 6,400 barrels per day (bpd) by 2020 from 2,700 bpd. More than half of that total $118 billion will be for E&P, according to Petrobras. The company already plans to contract 136 special vessels, 10 production platforms and floating production, storage, and offloading (FPSO) units, and 24 drilling rigs until And it expects to take on an additional 145 special vessels, 40 platforms and FPSOs, and 26 drilling rigs from 2013 to The size of these investments will transform the entire oil and gas industry in Brazil and increase its importance to the country, potentially even persuading international companies to establish local operations. Oil production exceeds refining capacity in Brazil, so Petrobras downstream business also has a sizable budget of $74 billion. Petrobras is building four new refineries, which should expand its capacity to 3,000 bpd in 2020 from 2,000 bpd today. 18

19 Petrobras faces significant challenges to put its impressive investment program in place, in our view. The ultra-deep waters where its oil reserves are located will require sophisticated technologies and highly qualified workers, though the company is already a major player in offshore drilling. Logistics will also be an issue, because the pre-salt reserves are more than 300 kilometers from the coast. A positive for Petrobras, in our view, is that its research and development group is working with other stakeholders and university centers to develop new technologies and attract and train qualified personnel. Another potential challenge is the growing financing demand. We expect Petrobras to fund its program with a mix of cash from its operations, cash at hand, and external financing. Even at times of financial markets turbulence, it has been able to tap the markets and count on government support, as it did during the liquidity crisis in We think the company will rely on natural long-term local funding sources, such as BNDES (Brazilian Development Bank) and multilateral development and export credit agencies, as well as local and international debt and capital markets. However, the company would likely seek partnerships as well to maximize its own capital commitments. Also, Petrobras will likely continue to support its suppliers through Progredir, a program that provides financing backed by Petrobras receivables, without leveraging its own balance sheet. PEMEX Needs To Invest To Sustain Its Production PEMEX, meanwhile, must also make significant capital expenditures to maintain its current production as well as to increase Mexico s proved hydrocarbons reserves. The company s business plan contemplates spending about $114 billion from 2012 to 2016, which represents an investment of $23 billion per year, with the goal of increasing PEMEX s production to 2,750 million barrels per day (mbd) by 2014 and improving its proven reserves replacement rate to 100% by As with Petrobras, most of the planned spending will go to exploration and production. Around 82% of the total capital expenditure budget is for developing upstream projects to increase and improve Mexico s oil and gas reserves. The remaining 18% will go toward downstream operations, mainly to improve PEMEX s logistics and distribution services. To increase production, the company launched its first round of three integrated contracts for mature oil fields in the southern region of Mexico during the third quarter of These contracts consider three areas: Santuario, Carrizo, and Magallanes, which together incorporate six fields. This will increase production by up to 55 million bpd, the company says. PEMEX expects to start the second round of integrated contracts during the fourth quarter of 2011 for six mature fields in the northern region of the country. The total investment for these six fields will be around $2 billion and will increase the company s production by 70 million bpd, according to PEMEX. The last round will develop deep-water production in the Gulf of Mexico. Other key investments by PEMEX in the next few years will be to offset the Cantarell Field s declining oil production and to develop new fields. In 2004, Cantarell located in Campeche Bay in the Gulf of Mexico contributed more than 63% of PEMEX s total production. As of Sept. 30, 2011, it contributed only 20% of the total with an average monthly rate of decline of 1%. The company is offsetting the decline in production with the development of significant existing oil fields, such as Ku-Maloob-Zaap, Crudo Ligero Marino, Ixtal-Manik, Delta del Grijalva, and Ogarrio- Magallanes. In the downstream segment, the company is building a new refinery in Tula, Mexico, which PEMEX expects to begin operating in 2016 and to process 250,000 bpd of crude oil per year. In the meantime, the company has also completed reconfiguration work on its Minatitlan refinery, in the eastern state of Veracruz, and expects production at the two refineries to stabilize by the end of In our view, the main challenge for PEMEX is its current reliance on mature fields, and the significant investments the company needs to make to maintain its current production. We believe that PEMEX will continue to require external financing to support its investment program. Although the company s ability to make capital expenditures is limited by the substantial taxes it pays to the Mexican government, PEMEX has ample access to bank financing and to domestic and international capital markets to support its spending. Government Support Is Key We believe that Petrobras and PEMEX s sizable capital expenditure programs will weaken their credit metrics and will result in the companies having negative free cash flows for the next few years. But the companies are also becoming more and more important to the economic growth of Brazil and Mexico, increasing the chances that both governments would provide timely and extraordinary support to them, if needed. Because of these strong links, we don t expect to take a negative rating action on Petrobras or PEMEX in the near future unless, of course, we change either country s sovereign rating or our view on the government likelihood of support. CW For more articles on this topic search RatingsDirect with keyword: Oil Companies Analytical Contacts: Paula Martins São Paulo (55) Fabiola Ortiz Mexico City (52) Standard & Poor s CreditWeek December 14,

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