Oil And Gas Companies - Standard & Poor's

CreditMatters | Multimedia edition 

CreditWeek® 

The Global Authority On Credit Quality | December 14, 2011 

Sovereign And Bank 

Rating Linkages 

Europe’s Economy: 

Back In Recession 

Special RepoRt 

Oil And Gas 

Companies 

commodity prices aren’t 

the only credit Factor 

Eurozone Trade Balances 

Weigh On Growth

COVER IMAGE: CORBIS 

contents 

2 www.creditweek.com 

4 

Oil And Gas Companies: Commodity Prices Aren’t 

The Only Credit Factor 

By Thomas Watters, New York 

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 

December 14, 2011 | Volume 31, No. 47 

Special Report 

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. 

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. 

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 2012. 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.

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 

2011. 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 2012. 

13 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, 2011 3

features special report 

4 www.creditweek.com

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. 




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 

2012. 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) 212-438-7818

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 2012. 



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 Rig Count 

Oil and gas 

1,200 

1,100 

1,000 

900 

800 

700 

600 

500 

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 2011. 

Chart 2 Rig Counts 

Total onshore and offshore 

2,200 

2,000 

1,800 

1,600 

1,400 

1,200 

1,000 

Jan. 2010 April 2010 July 2010 Oct. 2010 Jan. 2011 April 2011 July 2011 Oct. 2011 


© Standard & Poor’s 2011. 

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 2012. 

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 

2012. 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 


Drillers 

Analytical Contacts: 

Lawrence Wilkinson 

New York (1) 212-438-1882 

Paul B. Harvey 

New York (1) 212-438-7696

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. 



Chart 1 U.S. Oil And Natural Gas Rig Count 

1,800 

1,600 

1,400 

1,200 

1,000 

800 

600 

400 

200 

0 

Oil rigs Natural gas rigs 

1/7/2005 

4/7/2005 




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 

7/7/2005 

10/7/2005 

1/7/2006 

4/7/2006 

7/7/2006 

10/7/2006 

1/7/2007 

4/7/2007 

7/7/2007 

10/7/2007 

1/7/2008 

4/7/2008 

7/7/2008 

10/7/2008 

1/7/2009 

4/7/2009 

7/7/2009 

10/7/2009 

1/7/2010 

4/7/2010 

7/7/2010 

10/7/2010 

1/7/2011 

4/7/2011 

7/7/2011 

10/7/2011 

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,

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 2008. 

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 2011. F&D costs have 

declined about 15%, on average, since 

2008 because of improved drilling tech- 

Key Assumptions In Internal Rates Of Return Calculation 

niques 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 

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) 39 4.2 100 6.6 65 6.5 20 12 1.67 

Granite Wash (liquids rich) 22 4.0 55 8.0 65 9.0 15 8 1.50 

Bakken (non-core) 15 3.6 100 5.4 65 8.5 20 12 1.67 

Eagle Ford (liquids rich) 10 3.0 70 6.0 75 9.0 25 8 1.00 

Eagle Ford (oil) 10 2.4 78 4.8 75 9.0 25 8 1.00 

Marcellus (liquids rich) 11 6.0 27 4.5 65 6.0 13 5 1.06 

Cana-Woodford 11 7.5 38 5.5 55 8.0 20 7 1.00 

Haynesville (core) 12 10.0 0 15.0 81 9.0 25 8 0.70 

Fayetteville 5 3.0 0 3.3 63 3.0 20 4 1.00 

Barnett 5 3.0 0 2.9 60 2.8 20 3 1.00 

Marcellus (dry gas) 3 6.0 0 4.5 65 6.0 13 5 1.06 

Eagle Ford (dry gas) 3 6.0 0 10.9 80 8.0 25 8 1.00 

Haynesville (non-core) N.M. 7.5 0 6.0 81 8.0 25 8 0.70 

Piceance N.M. 0.9 0 1.7 60 1.9 19 6 0.97 

Woodford N.M. 4.0 0 4.5 60 7.0 19 7 0.70 

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. 



Chart 2 Internal Rates of Return* Of Major Shale Plays 

(%) 

45 

40 

35 

30 

25 

20 

15 

10 

5 

0 

(basis points) 

1,000 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

Bakken–core 

First year decline 

Granite Wash–liquids rich 



Well cost 

Bakken–non-core 

Haynesville–core 

IP rate 


Marcellus–liquids rich 

Year 1 

natural gas price 

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 

Chart 3 Impact Of Various Factors On Internal Rates Of Return 

Cana-Woodford 

*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. 



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 


Drilling 


Carin Dehne-Kiley 

New York (1) 212-438-1092

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 2012. (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. 




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. 

Chart 1 Future Brent-WTI Crude Price Differential 

($/bbl) 

Brent (left scale) WTI (left scale) Brent-WTI Differential (right scale) 

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 2012. 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 

110 

108 

8.8 

106 

8.4 

104 

102 

8.0 

100 

7.6 

98 

7.2 

96 

94 

92 

6.8 

6.4 

90 

Jan. 2012 March 2012 May 2012 July 2012 Sept. 2012 Nov. 2012 Jan. 2013 

6.0 

March 2013 

As of Dec. 5, 2011. 

Source: Bloomberg. 


Chart 2 Brent-WTI Crude Price Differential 

($/bbl) 

30 

25 

20 

15 

10 

5 

0 

1/2/2011 

2/2/2011 

As of Dec. 5, 2011. 



3/2/2011 

4/2/2011 

5/2/2011 

6/2/2011 

7/2/2011 

8/2/2011 

9/2/2011 

10/2/2011 

11/2/2011 

($/bbl) 

12/2/2011

Chart 3 Future Brent-WTI 3-2-1 Crack Spreads 

($/bbl) 

Brent 3:2:1 WTI 3:2:1 

20 

18 

16 

14 

12 

10 

8 

6 

4 

2 

0 

Jan. 2012 March 2012 May 2012 July 2012 Sept. 2012 Nov. 2012 Jan. 2013 March 2013 

As of Dec. 5, 2011. 



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 


Refiners 


Paul B. Harvey 

New York (1) 212-438-7696 




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.



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. $) 

25 

20 

15 

10 

5 

0 

30 

35 

40 

55 

50 

45 

60 

65 

2005 2006 2007 2008 2009 2010 

14.1 

11.7 

23.7 

33.7 

45.3 

60.4 

Petrobras PEMEX Petroleos de 

Venezuela S.A. 

Sources: Company reports. 



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 

18.8 

16.5 

11.8 15.0 

9.7 10.2 

7.7 

13.1 

7.3 

4.4 

15.3 

12.9 

6.8 

3.6 5.8 

1.6 

0.5 0.9 

0.5 

0.40.30.40.4 0.4 0.2 0.30.10.20.30.4 

Empresa 

Nacional del 

Petroleo (Chile) 

National Gas 

Company of 

Trinidad & 

Tobago Ltd. 

0 0.30.5 

0.3 

Petroleum Co. 

of Trinidad & 

Tobago Ltd. 

0.60.5 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 2030. 

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 2013. 

And it expects to take on an additional 

145 special vessels, 40 platforms and 

FPSOs, and 26 drilling rigs from 2013 

to 2020. 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.

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 2009. 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 2012. 

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 2011. 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 2011. 

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 


Oil Companies 

Analytical Contacts: 

Paula Martins 

São Paulo (55) 11-3039-9731 

Fabiola Ortiz 

Mexico City (52) 55-5081-4449 


contacts 

Global Ratings Network 

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Suite 1601, 16/F Tower D, Beijing CITC 

A6 Jian Guo Men Wai Da Jie 

Beijing, China 100022 

(86) 10-6569-2909 

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225 Franklin Street, 15th Floor 

Boston, MA 02110-2804 

(1) 617-530-8308 

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Torre Alem Plaza, Av 

Leandro N. Alem 855 

C1001AAD, Buenos Aires, Argentina 

(54) 114-891-2128 

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130 East Randolph Street, Suite 2900 

Chicago, IL 60601 

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Lincoln Plaza 

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The Gate Village, Building 5-Level 2 

PO Box 506650 

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60311 Frankfurt-am-Main, Germany 

(49) 69-3399-9110 

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Melrose Arch 

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(27) 11-214-1991 

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17-7, The Boulevard 

Mid Valley City, Lingkaran Syed Putra 

59200 Kuala Lumpur, Malaysia 

(60) 3-2284-8668 

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20 Canada Square, Canary Wharf 

London E14 5LH, U.K. 

(44) 20-7176-3800 

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Jose Tora 

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28006 Madrid, Spain 

(34) 91-389-6969 

www.standardandpoors.com 

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Level 45, 120 Collins Street 

Melbourne VIC 3000, Australia 

(61) 3-9631-2000 

Mexico City 

Victor Herrera, Jr. 

Punta Santa Fe Torre A 

Prolongacion Paseo de la Reforma 1015 

Col. Santa Fe 

Deleg. Alvaro Obregon 

01376 Mexico City, C.P. 

(52) 55 5081-4410 

Milan 

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Vicolo San Giovanni sul Muro 1 

20121 Milan, Italy 

(39) 02-72111-1 

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CRISIL House 

Cts Number 15 D 

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J.T. Chae 

2Fl, Seian Building 

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Prudential Tower, #17-01/08 

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Singapore 049712 

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111 87 Stockholm, Sweden 

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