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CreditWeek
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December 14, 2011
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Rating Linkages
Speci al Repo
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Oil And Gas
Companies
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ommodity
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rices
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dit Factor
CreditMatters
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Multimedia
e
dition
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.
2 www.creditweek.com
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 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.
contents
4
December 14,2011
| Volume 31, No. 47
COVER IMAGE: CORBIS
Special Report
Standard & Poor’s CreditWeek | December 14, 2011 3
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 Contr
act 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 land-
based 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 P
etrobras
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.
Multimedia
16 Podcast:(Portugese) Por Quê A Pemex E Petrobras
Vêm A
umentando 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 Inv
ersión 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
4 www.creditweek.com
features special report
Standard & Poor’s CreditWeek | December 14, 2011 5
W
ith 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.
Oil And Gas Companies
Commodity Prices Aren’t The
Only Credit Factor
Naturally, global integrated explo-
ration and production (E&P) compa-
nies that concentrate on oil are bene-
fiting greatly from sustained high
crude pri ces, as are the servi ce
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 ti me,
Standard & Poor’s Ratings Services
bel i eves thi s vi ew onl y begi ns to
describe the opportunities and chal-
lenges in the oil and gas industry.
For example, investment grade (rated
‘BBB-’ or higher), integrated North
American oil and gas companies con-
tinue to adjust their portfolios of assets
by selling low-value, low-return proper-
ties or businesses (such as refineries). As
a result, borrowers with broadly diver-
sified 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 rea-
sonable prices.
Moreover, some smaller, specula-
tive-grade (rated ‘BB+’ or lower) firms
are also taking advantage of favorable
capital markets—and interest rates—
to increase their oil and gas produc-
tion through acquisitions. Companies
with some financial cushion or a will-
ingness to use both equity and debt to
finance acquisitions will suffer fewer
negative effects on their creditworthi-
ness than those with comparatively
weak liquidity and high levels of debt,
in our view.
Meanwhile, natural gas E&P com-
panies may not be sufficiently cov-
ering 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 resul t, to thei r credi t rati ngs.
Although many companies are shifting
their spending to oil and liquefied nat-
ural gas, getting such production run-
ning may take longer and cost more
than they anticipate.
Alternatively, demand for drilling
services looks set to remain healthy in
2012. Increasing demand from oil-
focused players should continue to
more than offset declines related to nat-
ural 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 mar-
ginally 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
6 www.creditweek.com
features
special report
Analytical Contact:
Thomas Watters
New York (1) 212-438-7818
For more articles on this topic search RatingsDirect with keyword:
Oil and Gas
We expect credit quality for the U.S. oil and
gas sector to remain relatively stable into
2012, despite a still-fragile economic recovery.
W
ith crude oil averaging above
$90 a barrel and exploration
and production (E&P) compa-
nies demanding more (and more-varied)
drilling services, 2011 has been a busy
year for North American drilling compa-
nies. 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 over-
supply and equipment upgrade and certifi-
cation costs, which, coupled with debt-
financed growth activities, made 2011 the
third successive year of declines in prof-
itability 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’ per-
formance continues to strengthen, with
increasing demand from oil-directed plays
more than offsetting declines for natural
gas. High oil prices have led E&P compa-
nies 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
Standard & Poor’s CreditWeek | December 14, 2011 7
High Oil Prices Buoy Prospects For North
American Contract Drillers’ Credit Quality

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.
Overview
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
utilization and even some further strength-
ening of day rates in the first half of the year.
However, the cost of newly built rigs sched-
uled 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/Sta-
ble/—) and Pioneer Drilling Co.
(B/Stable/—), continued gains in both uti-
lization 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
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 con-
tract drillers—such as Diamond Offshore
Drilling Inc. (A-/Stable/—), Noble Corp.
(BBB+/Stable/—), Ensco PLC (BBB+/Neg-
ative/A-2), and Transocean Inc. (BBB-/Neg-
ative/A-3)—have seen successive declines
in profitability and credit protection meas-
ures. While rig oversupply and the resulting
erosion in day rates and utilization have
played a role, other factors have been influ-
ential as well. Post-Macondo safety and
equipment standards have resulted in more
out-of-service time and greater mainte-
nance expenditures than many issuers
expected. Furthermore, a number of off-
shore 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 compa-
nies. 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 uti-
lization 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 earn-
ings from recent fleet additions begin to
show up in the companies’ results.
CW
8 www.creditweek.com
features
special report
January 2010 May 2010 September 2010 January 2011 May 2011 September 2011
400
500
600
700
800
900
1,000
1,100
1,200
Oil and gas
Source: Baker Hughes Inc.
© Standard & Poor's 2011.
Oil
Gas
Chart 1
Rig Count
Jan. 2010 April 2010 July 2010 Oct. 2010 Jan. 2011 April 2011 July 2011 Oct. 2011
1,000
1,200
1,400
1,600
1,800
2,000
2,200
Total onshore and offshore
Source: Baker Hughes Inc.
© Standard & Poor’s 2011.
Chart 2
Rig Counts
Analytical Contacts:
Lawrence Wilkinson
New York (1) 212-438-1882
Paul B. Harvey
New York (1) 212-438-7696
For more articles on this topic search RatingsDirect with keyword:
Drillers
D
espite a 75% drop in U.S. natural
gas prices since mid-2008, com-
panies 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 pro-
duction (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 cov-
ering 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 uneco-
nomic 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
Standard & Poor’s CreditWeek | December 14, 2011 9
Is Natural Gas Drilling
Economic At Current Prices?

We don’t believe E&P companies
are covering their total costs for dry
natural gas producti on wi th
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.
Overview
a peak of 1,600 in September 2008, the
number of rigs actively drilling for nat-
ural 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 associ-
ated with unconventional natural gas
shales. Compared with conventional
plays, shale reservoirs tend to be more
uniform across a broad area and there-
fore generally carry lower exploration
risk. Shale reservoirs have other differ-
ences compared with conventional gas
fields. Those include higher initial pro-
duction (IP) rates relative to estimated
ultimate recoveries, hyperbolic produc-
tion 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
and our commodity price assumptions.
Our current natural gas price assump-
tion 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 gener-
ates 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 forma-
tions (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 gen-
erates 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 www.creditweek.com
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0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
Source: Baker Hughes Inc.
© Standard & Poor’s 2011.
Oil rigs
Natural gas rigs
Chart 1
U.S.Oil And Natural Gas Rig Count
and, finally, the first year natural gas
price. A shift in production taxes, oper-
ating 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 develop-
ment (F&D), lifting, production taxes,
cash general and administrative (G&A)
expense, and interest (including capital-
ized 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-
niques and the booking of proved unde-
veloped 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 con-
tinue 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 gener-
ated 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 nat-
ural 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
Standard & Poor’s CreditWeek | December 14, 2011 11
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.
Key Assumptions In Internal Rates Of Return Calculation
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
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 rea-
sons 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 com-
petitive 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 effi-
ciencies or falling costs for oilfield
services); and

A belief that natural gas prices will be
higher in the future.
Nevertheless, we believe that com-
panies 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 pro-
duction 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
12 www.creditweek.com
features
special report
First year decline
Well cost
IP rate
Year 1
natural gas price
LT natural gas price
Royalty rate
Production taxes
Production cost
Estimated
ultimate recoveries
0
100
200
300
400
500
600
700
800
900
1,000
(basis points)
Source: Standard & Poor’s.
© Standard & Poor’s 2011.
Chart 3
Impact Of Various Factors On Internal Rates Of Return
Bakken–core
Granite Wash–liquids rich
Bakken–non-core
Haynesville–core
Marcellus–liquids rich
Cana-Woodford
Eagle Ford–liquids rich
Eagle Ford–oil
Fayetteville
Barnett
Marcellus–dry gas
Eagle Ford dry gas
0
5
10
15
20
25
30
35
40
45
(%)
*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.
© Standard & Poor’s 2011.
Source: Standard & Poor’s.
Chart 2
Internal Rates of Return* Of Major Shale Plays
Analytical Contact:
Carin Dehne-Kiley
New York (1) 212-438-1092
For more articles on this topic search RatingsDirect with keyword:
Drilling
U
.S. refiners operating in the Midwest
(PADD II) and Rocky Mountain
(PADD IV) regions are likely to con-
tinue to outperform refiners in U.S. coastal
regions in 2012. (In the 1940s, govern-
ment 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
Standard & Poor’s CreditWeek | December 14, 2011 13
Why U.S. Refiners In The Midwest
And Rockies Should Outperform
Peers In 2012

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.
Overview
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 com-
panies—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 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 $13 per barrel (bbl)
(see chart 2). Meanwhile,TransCanada
Corp. (A-/Stable/—) has announced that it
will seek permits to construct the southern
leg of the Keystone XL pipeline from
14 www.creditweek.com
features
special report
Jan. 2012 March 2012 May 2012 July 2012 Sept. 2012 Nov. 2012 Jan. 2013 March 2013
90
92
94
96
98
100
102
104
106
108
110
($/bbl)
6.0
6.4
6.8
7.2
7.6
8.0
8.4
8.8
As of Dec. 5, 2011.
Source: Bloomberg.
© Standard & Poor’s 2011.
Brent (left scale)
WTI (left scale)
Brent-WTI Differential (right scale)
($/bbl)
Chart 1
Future Brent-WTI Crude Price Differential
1/2/2011
2/2/2011
3/2/2011
4/2/2011
5/2/2011
6/2/2011
7/2/2011
8/2/2011
9/2/2011
10/2/2011
11/2/2011
12/2/2011
0
5
10
15
20
25
30
($/bbl)
As of Dec. 5, 2011.
© Standard & Poor’s 2011.
Source: Bloomberg.
Chart 2
Brent-WTI Crude Price Differential
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 advan-
tage Midwest and Rockies refiners enjoy,
however. Based on futures contracts, we
expect the Brent-WTI differential to
average around $8.25 per barrel in 2012
(see chart 3). Although the Seaway reversal
will help alleviate the glut of oil at Cushing
refineries, the initial 150,000 bpd capacity
falls short of what’s needed to end the bot-
tleneck at the Cushing Hub. In addition,
we expect production from the Bakken
Shale as well as crude from Canadian oil
sands to continue to sell at a discount to
WTI because of pipeline constraints.
A Temporary Cushion
For Refiners
The strong refining margins we’ve seen this
year in the Midwest and Rocky Mountain
regions are somewhat of an anomaly, and
we expect them to continue to weaken over
time. In particular, regional advantages
could return to more historical levels
starting in 2013 as the Seaway and
Keystone XL pipelines alleviate the crude
oil bottleneck at the Cushing hub. Midwest
and Rockies refiners have generated strong
cash flows and earnings, but our assess-
ments of their business risk profiles limit
the ratings. In general, we would want to
see an improved scale of operations,
including more markets, and more
throughput capacity or number of
refineries prior to an upgrade. Nevertheless,
generally improved liquidity and financial
ratios provide these refiners a buffer against
negative rating actions in the next 12
months, in our opinion. Absent a signifi-
cant drop in margins across all regions—
such as occurred in 2009—Midwest and
Rockies refiners should continue to out-
pace their peers in coastal regions.
CW
Standard & Poor’s CreditWeek | December 14, 2011 15
Jan. 2012 March 2012 May 2012 July 2012 Sept. 2012 Nov. 2012 Jan. 2013 March 2013
0
2
4
6
8
10
12
14
16
18
20
($/bbl)
As of Dec. 5, 2011.
© Standard & Poor’s 2011.
Source: Bloomberg.
Brent 3:2:1
WTI 3:2:1
Chart 3
Future Brent-WTI 3-2-1 Crack Spreads
The narrowing of the price differential likely
doesn’t mean an end to the advantage
Midwest and Rockies refiners enjoy.
Analytical Contact:
Paul B. Harvey
New York (1) 212-438-7696
For more articles on this topic search RatingsDirect with keyword:
Refiners
I
f 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 www.creditweek.com
Big Spenders
features
special report
Latin America’s National Oil Companies,
Petrobras And PEMEX

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.
Overview
Standard & Poor’s CreditWeek | December 14, 2011 17
Risk is relative, however, for the two
largest national oil and gas companies
in Latin America. Their status as gov-
ernment-related entities (GREs) makes
them a key ingredient in Brazil’s and
Mexi co’s reci pe for sti mul ati ng
growth. This has created an interde-
pendency between companies’ and
governments’ plans that makes the
two companies’ expansion look fea-
sible—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
sovereign, is attracting high govern-
ment 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 poten-
tial 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 signifi-
cant 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 compa-
rable 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
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 i s al so l i kel y, 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 cur-
rent 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 pro-
duction platforms and floating produc-
tion, 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 compa-
nies to establish local operations. Oil
production exceeds refining capacity in
Brazil, so Petrobras’ downstream busi-
ness 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 www.creditweek.com
features
special report
Petrobras PEMEX Petroleos de
Venezuela S.A.
Ecopetrol S.A.
(Colombia)
Empresa
Nacional del
Petroleo (Chile)
National Gas
Company of
Trinidad &
Tobago Ltd.
Petroleum Co.
of Trinidad &
Tobago Ltd.
0
5
10
15
20
25
30
35
40
45
50
55
60
65
(Bil. $)
Sources: Company reports.
© Standard & Poor’s 2011.
2005
2006
2007
2008
2009
2010
14.1
23.7
33.7
45.3
60.4
9.7
15.0
4.4
18.8
15.3
0.5
0.9
3.6
5.8
0.4
0.30.40.4 0.4 0.20.30.10.2
0.30.4
0
0.3
0.3
11.7
16.5
10.2
11.8
7.7
13.1
7.3
12.9
6.8
1.6
0.5
0.5
0.6
0.5
Oil Companies’ Adjusted Capital Expenditures
Their status as government-related entities
makes them a key ingredient in Brazil’s and
Mexico’s recipe for stimulating growth.
Petrobras faces significant chal-
lenges to put its impressive investment
program in place, in our view. The
ul tra-deep waters where i ts oi l
reserves are l ocated wi l l requi re
sophisticated technologies and highly
qualified workers, though the com-
pany is already a major player in off-
shore 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 develop-
ment 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 turbu-
lence, it has been able to tap the mar-
kets and count on government sup-
port, as it did during the liquidity
crisis in 2009. We think the company
will rely on natural long-term local
fundi ng sources, such as BNDES
(Brazilian Development Bank) and
multilateral development and export
credit agencies, as well as local and
international debt and capital mar-
kets. However, the company would
likely seek partnerships as well to
maximize its own capital commit-
ments. Also, Petrobras will likely con-
tinue to support its suppliers through
Progredir, a program that provides
financing backed by Petrobras’ receiv-
ables, without leveraging its own bal-
ance 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 com-
pany’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 wi th Petrobras, most of the
planned spending will go to explo-
ration 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 con-
tracts for mature oi l fi el ds i n the
southern region of Mexico during the
third quarter of 2011. These contracts
consi der three areas: Santuari o,
Carri zo, and Magal l anes, whi ch
together incorporate six fields. This
will increase production by up to 55
mi l l i on 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 bil-
lion and will increase the company’s
producti on by 70 mi l l i on 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 pro-
duction and to develop new fields. In
2004, Cantarell—located in Campeche
Bay in the Gulf of Mexico—con-
tributed 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 offset-
ting 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 seg-
ment, 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 produc-
tion. We believe that PEMEX will con-
tinue 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 bel i eve that Petrobras’ and
PEMEX’s sizable capital expenditure
programs will weaken their credit
metrics—and will result in the compa-
nies having negative free cash flows
for the next few years. But the com-
panies are also becoming more and
more i mportant to the economi c
growth of Brazi l and Mexi co,
increasing the chances that both gov-
ernments 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
Standard & Poor’s CreditWeek | December 14, 2011 19
Analytical Contacts:
Paula Martins
São Paulo (55) 11-3039-9731
Fabiola Ortiz
Mexico City (52) 55-5081-4449
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