moody's approach to rating the petroleum industry (2003).pdf

8/9/2019 Moody's approach to rating the petroleum industry (2003).pdf

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Rating Methodology

Summary

Moodys approach to rating petroleum companies starts from much the same point as other industrial companies. Weanalyze historical cash flow protection, financial performance, and operating trends to place a company in the contextof its peer group and broader industry conditions. Historical markers, however, are just the starting point: the primaryfunction of credit ratings is to provide an opinion on levels of future cash flow and asset protection and, consequently,the risk of default to debt holders.

The petroleum business, however, is not like a manufacturing operation, which can typically produce a new andimproved line of products every year as long as it has access to labor and materials. An oil and gas companys reservebase is finite and depletes with every barrel produced. To be successful, a petroleum company must reinvest substantialcapital year after year to find new reserves and replace production. Exploration success and reserve replacement have alarge element of geological risk but are also linked to companies locations, core legacy positions, and technologicaladvantages.

While financial results and ratios are important to credit rankings, an oil and gas companys record and futureprospects are not effectively or most directly captured in its income statement, cash flow, and balance sheet. To arriveat a more meaningful assessment of cash flow, asset protection and financial leverage, we look at a variety of petroleumreserve measures provided in supplemental disclosures and how they intersect with the financial statements. Each of

these measures has a specific purpose (as well as analytical limitations).In addition, the petroleum industry is a commodity business. Producers cannot control pricing, and competitive

conditions prevent them from passing on cost increases to consumers. Thus, we also focus on cost structure and oper-ating efficiency, elements within a companys control, as critical indicators of its ability to operate and service debt indifficult pricing and margin environments.

Finally, because of commodity price risk and high capital reinvestment risk, petroleum companies cannot bear theelevated financial leverage typical of a more stable cash generator such as a regulated utility. The higher the financialleverage, the lower rated a company is likely to be. For the same reason, larger integrated companies with more diver-sified cash flow and often countercyclical upstream and downstream operations are the highest rated companies in thepetroleum universe, while exploration and production companies, which lack the level of reserve diversification anddownstream integration, are more exposed to price risk and reserve success and are rated lower.

New York

Tho ma s S . C olema n 1.212.553.1653

J ohn DiazJ ohn Cassidy

Alexandra Parker

Andrew OramKenneth Austin

London

J eremy Ha w es 44.20.7772.5454

Sydney

Terry Fa nous 61.2.9270.8100

Tokyo

J unichi Ya ma ki 81.3.5408.4000

Hong Kong

Michelle Toh 852.2916.1120

Singapore

Chris Ma ynes 65.6398.8300

Contact Phone

December 2003

Moodys Approach to Rating the Petroleum IndustryThis special comment addresses the quantitative and qualitative factors that are important in

understanding and analyzing the rating of petroleum companies integrated oils,independent exploration and production companies, and refiner/marketers.


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2 Moody s Rating Methodology

Table of ContentsIntroduction ......................................................................................................................................................................3

Rating Process ...................................................................................................................................................................3

Petroleum Industry Structure And Fundamental Risks .................................................................................................4

Industry Structure ..................................................................................................................................................4Industry Fundamentals ..........................................................................................................................................5Moodys Approach To Commodity Price Risk ....................................................................................................6Sovereign And Regulatory Risks ...........................................................................................................................6

Upstream Operations And Petroleum Reserves .............................................................................................................7

Reserve Analysis Some Qualitative Issues .........................................................................................................7Asset Protection And Reserve Leverage Key Metrics ......................................................................................8Operating Success And Cost Structure ............................................................................................................. 10

Refining And Marketing Analysis ................................................................................................................................. 12Key Qualitative Issues ........................................................................................................................................ 12Quantitative Measures ........................................................................................................................................ 14

Financial AnalysisKey Measures and Ratios ............................................................................................................. 15

Cash Flow Protection ......................................................................................................................................... 15Capital Spending Analysis .................................................................................................................................. 16Financial Returns And Quality Of Earnings ..................................................................................................... 16

Financial Leverage And Balance Sheet Analysis ............................................................................................... 18Legal Structure And Covenants ......................................................................................................................... 19Financial Flexibility And Liquidity .................................................................................................................... 19

Quality Of Management ............................................................................................................................................... 19

Event Risk ...................................................................................................................................................................... 20Conclusion ..................................................................................................................................................................... 20

Other Related Research: ............................................................................................................................................... 20

Evaluating Managementa Brief Checklist ................................................................................................................ 21

Selected Petroleum Industry Terminology .................................................................................................................. 22

Sample Integrated Oil Credit Statistics....................................................................................................................24-29

Sample Independent Exploration and Production Credit StatisticsEOG Resources, Inc. .......................................30

Sample Independent R&M Credit Statistics ................................................................................................................ 31


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Moody s Rating Methodology 3

In t roduct ion

RATING PROCESSMoodys credit rating process for petroleum companies follows a systematic approach similar to other industrial com-pany analysis: we take a top down and bottom-up approach, starting with the macro-economic picture (broad politi-cal, economic, and industry environment), moving to an assessment of the companys operating and competitiveposition, and ending with its financial position and strategy. A companys financial statements, footnotes, and ratios areimportant to the process, supplying information to measure its health and ability to grow and providing a basis forcomparison with its peers. However, they are only part of the picture. Numbers as presented can be manipulated andsubject to different accounting treatments. Therefore, we look for ways to adjust financial statements and ratios toreflect a companys true underlying risks and what we believe to be its true economic worth. Analysis of the petroleumindustry also involves a set of specialized petroleum reserve and production measures intended to capture informationnot adequately reflected in an oil companys nominal financial statements.

Furthermore, while our long-term ratings capture historical debt protection measures and operating trends, our

focus is on forward financial protection and operating and cost trends, in essence trying to evaluate future operatingtrends, cash flow, earnings and balance sheets. Key determinants of a rating are the volatility of a companys cash flowand underlying debt coverages relative to the risks undertaken and to the companys peer group.

Rating

Qualitative AnalysisManagement

Strategic Direction

Financial Flexibility

Quantitative Analysis

Financial StatementsPast Performance

Future Performance

Mark et Position

Competitive Trends in Sector Global/Domestic

Regulatory Environment Global/DomesticSectoral (Industry) Analysis

Sovereign Macroeconomic Analysis

Moody's Rating Analysis Pyramid


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Petroleum Industr y Str uctur e and Fundamental Risks

INDUSTRY STRUCTUREThe petroleum industry encompasses a number of segments, the most important of which are:

The upstream, which involves exploration, development and production of oil, natural gas and naturalgas liquids; and

the downstream, which relates to refining, transportation, and marketing of refined products.

Many companies also engage in mid-stream businesses such as natural gas gathering and processing ofgas liquids, energy marketing, and downstream petrochemicals. These will not be covered in this report.

For analytical purposes, petroleum companies can be broadly divided into three groups, each with distinct operatingcharacteristics and credit profiles:

The integrated majorsengage in all phases of the business from petroleum exploration to refining and retail sales atthe gasoline pump. The majors by virtue of their large natural gas and capital resources are the prime movers in agrowing international liquefied natural gas (LNG) business on both the supply and receiving end. Many also haveextensive petrochemical operations. For them, petroleum is truly a global industry characterized by scale, geographicdiversification, and upstream and downstream counter-cyclical benefits that help stabilize cash flow. The integratedsare thus the most stable and highly rated companies in the industry, with an average rating of Aa3.

Independent exploration and production (E&P) companiesengage primarily in the exploration, development andsale of crude oil and natural gas reserves, as well as gas processing in some cases. Their cash flow and earnings are more

volatile and exposed to commodity price swings, even as they must re-invest substantial amounts to replace depletingreserves. Their reserve replacement and financial position can be more quickly impaired by commodity price declines,exploration or production setbacks, or other unforeseen events. Over time, the relative performance and credit qualityof the E&P companies are determined by operating returns on invested capital, the money spent acquiring, finding,and developing acreage and reserves, and the leveraging of reserves. Almost all of the independent E&P companies arerated lower in the Baa or speculative grade categories, reflecting commodity price and reserve replacement risk.

Independent refiner/marketers manufacture and sell refined products, purchasing their feedstocks from producerson the open market. The retail part of the business includes service stations networks and, increasingly, conveniencestores and fast food outlets. Refining and marketing are capital intensive, high volume and revenue businesses. Theyare subject to thin margins and volatile price swings on crude inventories. Competitive pressures rarely support richpricing at the pump for very long. The performance of small niche refiners can also be dominated by geographical orlogistical economics that magnify the effect (positive or negative) of larger refining industry trends. Volatile earnings,periodic cycles of non-discretionary environmental spending, and elevated financial leverage translate into low Baa and

speculative grade ratings for most of the refiner/marketers.

UPSTREAM

DOWNSTREAM

Production

Exploration

Gas Processing ChemicalsRefining

MarketingCoal

Transportation

Structure of the Oil Industry


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INDUSTRY FUNDAMENTALSIn assessing the credit risks facing petroleum companies, it is useful to remember a few key points about the industry:

Barriers to entry:The ability to establish a viable presence in the international petroleum industry is difficultdue to high barriers to entry in the form of capital, technological and drilling expertise, and required interna-tional skills. All of the major integrated players are long-established companies, as are many of the largestindependents, which have grown organically and through mergers and acquisitions. In an industry character-ized by mergers and consolidations over the last two decades, the only significant new entrants have beennational oil companies, who in many cases have formed their own E&P units or can parlay their countrysresources into joint ventures with experienced explorers and developers. National oil companies have becomesavvy participants as well as head-to-head competitors with the major private sector companies in both theupstream and downstream.

Commodity Price Risk:Crude oil and refined products are commodities priced and traded in U.S. dollars

on a global basis. Producers and refiners are price takers due to conditions of ample supply, lack of OPECdiscipline, the emergence of large non-OPEC supplies, and industry competition. Consequently, economiesof scale and cost competitiveness are critical to profitability. Natural gas, in contrast, is more regional in itsproduction and sales patterns (except in liquefied form) since market penetration is limited by pipeline accessand physical proximity. Natural gas prices are only somewhat de-linked from oil prices since they competewith fuel oil in certain North American industrial and power markets, and in international markets such andEurope and Asia sales contracts are usually linked to crude price baskets.

Depleting Resource Base:Oil and natural gas are depleting assets. A company must spend consistently andsuccessfully over a long-period of time to replace and grow its production base. Otherwise, its reserves andmarket value will dwindle and the company will eventually liquidate. Many of the majors and most of theinvestment grade E&Ps have core production concentrated in mature older basins in North America and theNorth Sea, and the challenge is to grow production, while maintaining a competitive cost structure. Further-more, while technological advances have improved recovery rates, they have also increased depletion rates

and exacerbated the reserve replacement and unit cost challenge. The challenge is likely to become more dif-ficult in the future, particularly for companies concentrated in these mature areas.

Cyclicality:The petroleum industry is inherently cyclical, following global and regional patterns of economicgrowth and product demand and industry patterns of investment, surplus and shortage. We aim, as much aspossible, to rate companies through the cycle, which means that at any given point in time a companys rat-ing could look too high or low or might not correlate closely with its financial measures.

Asset Valuation: Historical financial statement accounting is limited in its ability to reflect true reserve andequity values, due to fluctuating commodity prices, reserve performance, cost escalation, and the inherentuncertainty in measuring reserves in the ground. Reserve quantification and valuation are part art and partscience, and the value of reserves in the ground is subject to changing prices, technology, and skillful exploita-tion. To get a better picture of a petroleum companys asset values and financial leverage, we look at cash flowprotection, but also at a variety of reserve and production based measures that focus on operating success, costefficiency, leveraging of reserves, and net present value.

Petroleum Industry Peer Group Average Rat ing

$0

$5

$10

$15

$20

$25

$30

$35

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

OilPrice

perbarrel

0

1

2

3

4

5

6

7

8

9

10

Average

Rating

Brent (Avg Annual) Refiners Integrated Majors Oil Service E&

Aaa

Aa1Aa2

Aa3

A1

A2

A1

Baa1

Baa2

Baa3

B1


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MOODYS APPROACH TO COMMODITY PRICE RISKIn order to rate through the cycle our ratings must take into account commodity price volatility and incorporate anormal range of oil and gas price fluctuations. Based on long-term trends in pricing fluctuation and continued OPEC

discipline, but also on the impact of emerging new supply sources, we view medium-term mean oil prices to be in thelow to mid-$20s/barrel range (WTI), but continue to stress test ratings in the range of $15-18/barrel. Natural gasprices used will be largely dependent upon location and in North America we stress test ratings in the range of $2.50-$3.00/mcf (Henry Hub). In a price range, we perform sensitivity analysis on earnings and cash flow and take a broadview on the probability that pricing will achieve those levels. This helps determine how well and for how long a com-pany can function at the low end of the price range without serious impairment of credit quality. It also helps pinpointthose companies most vulnerable to sustained price pressures.

Sensitivity testing involves a variety of company-specific factors such as oil and natural gas mix, current and pro-jected production decline rates, product quality differentials, actual price realizations, and cost structure. This analysisalso factors in the impact that lower pricing will have on a companys future reserve and production profile. We look at,for example, the impact that lower commodity prices may have on reserve bookings, on the flexibility to maintainspending and add new reserves, and on proved undeveloped reserves that could become uneconomic at lower prices.

A related consideration is the companys stance on hedging its commodity price risk. We look at how much of a

companys production is hedged and managements strategic reasons for hedging. In general, companies do not hedgeto enhance profits or fundamental competitive position. Investors buy oil and gas stocks as a commodity price play andcompanies do not want to give away the upside. Most companies hedge some portion of their production to dampenprice volatility and improve cash flow predictability in order to support a base level of strategic capital spending, whichtypically would include a large component of committed expenditures.

SOVEREIGN AND REGULATORY RISKSThe petroleum industry is almost unique in its high visibility and the critical political and economic roles it plays wher-ever it operates. In many countries, particularly in emerging nations with limited economic and resource diversifica-tion, oil is regarded as the national patrimony. It is both a vehicle for economic development and employment and thegovernments primary source of wealth. This has implications for political risk, government intervention, the setting ofnational budgets, upstream and downstream regulation, and taxation. Moodys considers all of theses factors whenassessing credit quality, and while some of them are more relevant to the large integrated oils, many independentE&Ps have significant exposures in developing countries that will increase as they pursue growth outside of NorthAmerica and the North Sea. Some key external factors we look at include:

Sovereign Risk:Sovereign analysis is frequently an important issue since many petroleum companies operateglobally and must invest in a country over long periods to become established players and recover their costs.Sovereign analysis involves a countrys macroeconomic and political framework, as well as some understand-ing of petroleums importance to a country, the states role in the industry, and the relationship between thenational oil company and foreign investors. Sovereign risk issues and the role of the state also factor heavilyinto the credit ratings of most wholly-owed or partly privatized state oil companies in Europe, the formerSoviet Union and Asia, where many companies have come to the capital markets in the past decade.

Contract Structure: Different countries allow different structures for participation in exploration and pro-duction, ranging from equity ownership of reserves to production sharing contracts and fixed fee- per-barrelarrangements. These structures affect the economics of exploration and development and a companys profit-

ability. They determine the relative attractiveness of competing investments as well as a countrys ability toattract foreign investment. The actual structure of contract payment flows can also be a critical political riskelement when a host country is under stress; e.g. whether a producer sells to or is directly reimbursed by thestate for expenses and production, or sells to third parties and is paid offshore.

Taxation and Royalties: In many regions such as the Middle East, Mexico and Venezuela, low cash produc-tion costs ($1-3 per barrel) leave a wide cash margin between the market price of oil and its production costs.This creates a natural target for governments, and the petroleum industry is heavily taxed in many forms,including royalties, severance at the wellhead, windfall profits, sales tax at the gasoline pump, and differentialincome taxes. Consequently, tax regimes and assumptions are integral to company drilling plans, field devel-opment economics, and reserve valuations. At the extreme, taxes can be a very real political risk since govern-ments in distress use tax policy as an effective and relatively easy way to raise revenues, particularly in lieu ofmore radical forms of intervention such as expropriation and nationalization.


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Regulation/Environmental Risk:Government regulation is prevalent in most parts of the industry, tendingto fall most heavily in the area of environmental issues. This is particularly true in the downstream sector,which is subject to legislation on clean products (low sulfur gasoline and diesel), MTBE phase out, air andwater emissions, site remediation and regulation of product prices at the pump. In addition, government reg-ulation in certain countries such as South Korea and China favors the domestic refining and marketing indus-try. This reflects the strategic importance of oil to national economies and can be a supportive factor in theratings for these companies, with ratings that tend to be closely linked to the sovereign rating. In theupstream, many producers are environmentally constrained in key growth areas such as the deepwater Gulf ofMexico and the Rockies, and will also have to begin funding remediation and plugging and abandonmentactivities as mature North American and North Sea fields reach the end of their economic lives. These expen-ditures are mandatory if a company is to stay in business and they typically provide little or no capital return.We analyze environmental exposures on a case by case basis, including the share of capital spending allocatedto environmental projects, annual cash environmental costs, and the adequacy of the financial reserves estab-lished on an ongoing basis or for specific large liabilities. We also examine whether environmental outlays andrelated legal judgments could become reimbursable under company insurance coverages.

Upst ream Operat ions and Petrol eum ReservesOil and gas reserves and production are the primary source of cash flow and generally the highest return operations foran integrated or independent E&P company. The reserve base drives most of the key metrics and is the source of thecompanys greatest exposure to commodity price risk, capital re-investment, and market valuation. Reserve analysisfocuses on the quality or economic value of the reserves, portfolio balance, cost structure, and on the cash flow andvalue of production. Reserve analysis helps pinpoint a companys sensitivity to price declines, the source of poorreturns, high cost acquisitions, over-valued reserves, and exposure to earnings charges and book writedowns.

Because of the limitations of accounting, we analyze various reserve and production measures and how they inter-sect with the financial statements to get a better picture of the asset and cash flow protection for debt holders and thequality and efficiency of a companys operations. Many of these measures can be derived from the annual disclosuresmandated by the SEC pursuant to FAS No. 69 Disclosures about Oil and Gas Producing Activities. In addition, inareas such as high yield and project finance, our analysis often utilizes third party reservoir engineering reports. For

some non-U.S. companies that do not comply with FAS reporting standards, we make our own adjustments for com-parability. These often concern the classification and valuation of reserves as proved, probable and possible. (Please seeGlossary for definitions of some terminology.)

These data should be analyzed over time (three, five and ten year periods are most common) to discern trends andto smooth out single-year anomalies in reserve bookings or finding costs and the impact of one-time events. Multi-year analysis also better reflects the multi-year petroleum investment cycle and the long-term perspective needed tobuild reserve value.

RESERVE ANALYSIS SOME QUALITATIVE ISSUESReserve-based measures point up significant company and industry trends and provide the basis for further analysis ofa companys operations. However, a number of qualitative issues need to be considered to understand a companysnumbers and assess its current and future production and cash flow prospects.

Scale of Operations:We take a broad look at the absolute size of a companys reserves and production, their geo-graphic diversity or concentration and, as previously noted, some assessment of political risk. All other things equal, alarge well-diversified portfolio of production, staged development and exploration prospects provides better protec-tion to debt holders than a smaller operation with a high degree of field concentration.

Reserve Estimates and Booking Practices: Historical balance sheet accounting is limited to measuring a companysremaining historical cost incurred in finding and developing reserves, without reference to fluctuating commodityprices or the inherent uncertainty in measuring reserves. Reserve quantification and valuation is part art and part sci-ence. Management does have considerable flexibility with respect to the timing of reserve bookings and the quantity ofrecoverable reserves is subject to varying degrees of uncertainty. Recoverable reserves are only an estimate and there-fore subjective data points that are difficult to assess from public disclosures alone. Reserves frequently change handsand buyers and sellers often have different views on recoverable volumes. In addition, companies generally are lookingto show reasonable or acceptable growth in both production and reserves. A careful look at the sources of newlybooked reserves from drilling, revisions, field extensions, enhanced recovery, and acquisitions, and other patterns, suchas repeated downward revisions, is necessary and can be helpful in assessing how conservative or aggressive manage-ment is in financial disclosures and booking practices. Moreover, the extent to which different companies use indepen-


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dent reserve engineers varies significantly and can become a critical issue, particularly in evaluating independent E&Pcompanies. The challenge is compounded in analyzing reserves for some companies in emerging markets such as theformer Soviet Union, where the only reserve evaluations may be internally generated and not in compliance with SECor other international standards. Moodys believes the use of reputable independent reserve engineers can lead to moreconservative reserve bookings, but it does not eliminate reserve risk.

Location and Quality Differentials: In addition to the impact of commodity prices, the value of oil and gas reservesis affected by geographic location and quality (certain physical properties result in higher/lower realized prices).Reserve location has a major impact on costs, on establishing markets for production, and on political risk. While oilproduction is a global business and is readily traded by ship, natural gas opportunities are more tied to existing pipelineinfrastructure and localized demand. Prolific, high quality oil or gas reserves will have higher finding and developmentand transportation costs, and exact a high risk premium if they are remote and limited by infrastructure or politicalconsiderations.

The physical characteristics of petroleum reserves will affect finding and operating costs, revenue realizations, andupstream profits. A first look would involve the mix of oil and natural gas in the reserve and production base since pric-ing for the two commodities is driven by different factors. Physical properties refer to characteristics such as high-value light sweet crude vs. lower-value heavy sour crudes, metals content, dry vs. wet natural gas, and numerous other

factors. These determine a companys price realizations, which can deviate significantly from spot market indicatorssuch as West Texas Intermediate, Brent, or Henry Hub gas. Price realizations are also affected by contract sales terms,transportation/delivery differentials, and hedging practices.

Company Expertise:Companies often develop specific competitive advantages or areas of expertise, e.g. a long oper-ating history in a country or basin, technology such as horizontal drilling, or a type of play such as heavy oil. Relatedindicators include a companys large ownership or production sharing interest and status as a field operator, which giveit greater control over its capital spending and cash flows.

Integration: For integrated companies, equity access to specific crude slates and linkages between upstream equityreserves and downstream refining and chemical configurations can have a significant impact on profitability and oper-ating strategies.

ASSET PROTECTION AND RESERVE LEVERAGE KEY METRICS Barrel of oil equivalent (BOE) Reserves:A companys BOE reserves are its oil, natural gas and gas liquids

reserves expressed on an energy equivalent basis, usually converting natural gas to oil on a 6,000 BTU: 1 basis.This measure puts reserve calculations and different asset bases on a volume comparable basis.

Proved Reserves and PUDs: In analyzing company reserve data, we usually rely only on proved reserves.This approach reflects industry lending practices and provides a consistent and conservative approach to debtprotection (as opposed to equity valuation, which focuses on upside growth potential). Proved reserves comefrom known reservoirs and can be produced with reasonable certainty under current pricing and technolog-ical operating assumptions. Proved reserves are subdivided into categories that reflect differences in the tim-ing, certainty, and the capital needed to bring proved reserves into production and, therefore, the relative debtprotection in the proved reserves. Proved developed reserves (PDs) are produced from existing wells. Theyhave the greatest degree of certainty and are the primary source of operating cash flow, providing funds tomaintain existing production and invest in exploration and development for new reserves. Other sub-catego-ries are proved developed not producing (PDNPs), which may reflect shut-in production, technical problems,etc., and proved undeveloped (PUDs). Two other reserve categories are probable and possible reserves,reflecting lesser certainty, whether it is because of geology, required drilling, pricing or technology risks.While we generally dont give credit to these categories, they can be germane to the economics of reserveacquisitions and major project investments that precede reserve bookings.

PD reserves typically compose upwards of 75%-80% of the proved reserves of integrated companies. How-ever, in recent years PUDs have increased as a relative share of total proved reserves, particularly among theindependent E&Ps, most of which have 30% or more of their reserves booked as PUDs. While an increase inthe proportion of PUDs is not necessarily problematic, PUDs require capital investment and carry highergeological risk than developed reserves and can distort various reserve and cost metrics such as RLI, reserveleverage and cost structures. Their inclusion in total proved reserves can enhance the appearance of growth,when in fact they often require significant appraisal and development capital to attain developed status andproduction.

Reserve Life Index (RLI): In theory, the RLI measures how many years a company can produce hydrocarbonsat current production rates until reserves are depleted. RLI assumes no replacement of reserves. It isexpressed in years, and can be measured on a BOE basis, for either oil or natural gas, or on a total proved or


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the range of $1-$2 per BOE, with no debt allocated to other sectors than the upstream. For solid investmentgrade E&P companies, the ratio tends to be in the high $2.00 to high $3.00 per BOE range. It should beemphasized that we do not consider this metric in isolation. It may fluctuate depending on acquisition activity,capital spending needs relative to operating cashflow levels, and commodity prices, but it usually falls withinthose ranges for the highest rated companies in the peer group.

We note here, and discuss later, that we make numerous adjustments to the debt balance (numerator) toinclude off-balance-sheet and other debt-like obligations. A limitation of this measure that should be noted isthat for the integrated oil companies, or for independent E&Ps with other significant operations such as mid-stream or chemical assets, these reserve measures do not give credit to the cash generating and leveragingattributes of those businesses. For the integrateds, it is difficult to allocate a portion of the companys debt totheir large downstream and numerous other diversified operations and we tend to focus more on TD/BOE.On the other hand, for the independents we do often make internal adjustments or allocations of debt to non-E&P operations in making peer group comparisons. Typically we would use a cash flow multiple to determinethe amount of leverage the non-E&P operations can support and discuss the impact of that allocation on ourview of financial leverage with a companys management. These allocations are subject to change and inter-pretation, however, and we do not currently disclose those adjustments in our peer group calculations.

Cash Flow/BOE:

This measures a companys cash generation per BOE of current year production, based onSEC 10 results of oil and gas producing activities rather than the consolidated cash flow statement. The cashflow (net income + DD&A) is on an unleveraged basis, calculated after tax, but before corporate interestexpense.

OPERATING SUCCESS AND COST STRUCTURE Reserve Replacement Ratio:A company should replace at least 100% of its production every year or it will

eventually liquidate. This ratio is a key measure of drilling or operating success, or the ratio of reserves addedin a given year versus that years production. It can be refined to measure replacement from all sources orfrom discoveries, reserve extensions, or acquisitions. A careful look at the sources of replacement can get atthe quality of a companys drilling efforts and success over time. For example, a pattern of extensions andupward revisions could evidence conservatism in reserve booking practices, while frequent downward revi-sions could indicate liberal booking practices, unduly optimistic assumptions, or adverse changes in the eco-

nomic environment. Over the past decade, total reserve replacement for the majors has been on an improvingtrend, supported in large part by acquisitions. Most have showed strong replacement from all sources overboth three and five year periods, including field extensions and enhanced recovery, indicating the depth oftheir unbooked reserve positions and technological expertise. However, more stringent drill bit replacement(extensions and discoveries only) has been relatively poor in the 50%-70% range, reflecting the fundamentalchallenge of replacing large declining mature basins. Drill bit replacement for many of the stronger indepen-dents has been relatively higher, although core field declines and shrinking discoveries in core U.S. and Cana-dian basins are exacerbating the challenge in the E&P sector as well.

Changes in Reserves:The sources of changes in total reserves from year to year underpin a companys totalreserve replacement and can be categorized as follows: revisions, extensions & discoveries, purchases, produc-tion and asset sales. Purchases, production, and asset sales are fairly self-explanatory and provide useful infor-mation. However, reserve additions due to upward or downward revisions and to extensions & discoveriesmay shed even more light on key attributes of the reserve base and the effectiveness of capital invested. Nega-

tive reserve revisions can be related to reservoir performance or changes in commodity prices, or to both.This is not always clear from public disclosures, and significant negative performance-related revisions canindicate reserve problems. It is important to explore the reasons behind these negative revisions and whethersimilar problems may arise in other areas. Price-driven revisions also need to be assessed. The standard prac-tice is to estimate year-end reserves based on year-end commodity prices held constant (with some flexibilityto adjust for existing hedge positions). Moodys looks at how sensitive a companys reserve base is to changesin commodity prices, especially if prices are unusually high at the calculation date. Similarly, it is quite com-mon for international reserves to be subject to a production sharing agreement (PSA) or production sharingcontract (PSC). These are often structured to return more barrels to the host country when oil prices arehigh, resulting in a negative revision for the company. These contracts also provide some type of floor orrecovery mechanism when oil prices are low, resulting in a positive revision. Extensions and discoveries canalso add to the underlying reserve base and may provide an indication that exploration or development strate-gies are progressing as planned, but again, it is important to understand the nature of the change and theunderlying assumptions.


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Drilling Success Ratio: Drilling success measures the number of successful wells (finding hydrocarbons)drilled in a year as a percentage of total wells drilled. This ratio serves as an indicator of the companys currentsuccess and can be applied to exploration or development drilling success. However, it can be misleading.Exploration success signals hydrocarbon discoveries but does not necessarily mean a well will have reservequantities or flow at rates sufficient to be commercially viable. More qualitative information is usually neces-sary to make an informed judgment about drilling success

Finding & Development Costs (Replacement Costs) per BOE:This is a unit measure of the total costincurred to add and develop a barrel of new reserves to the point of production. The lower a companys F&Dcosts, the more profitable its oil and gas activities will be in a wider range of price environments. F&D costsare subject to numerous variables, including the complexity and size of the reservoir, reserve booking prac-tices, and timing issues such as development approvals. F&D costs are best measured over a period of years tocatch the inherent lag between capital spending and booking of reserves, and to reduce distortions caused byone-time events. We look at F&D costs from all sources (acquisitions + exploration + development) and fromdrilling only to better judge a companys drilling success (rather than from acquisitions). Industry wide, F&Dcosts have been rising fairly steadily since the late 1990s, reflecting reduced exploration, lower drill bitreplacement, rising service sector costs and more remote higher risk drilling areas. The largest majors havemanaged on an all-in basis to maintain fairly competitive F&D costs above $5/BOE on a volume weightedaverage basis, while most of the large E&Ps are somewhat higher in the $6.50-$7.00/BOE range, again show-ing a rising trend on a multi-year basis.

Production (Lifting) Costs per BOE:This measures the total current cash operating cost of bringing abarrel of oil to the surface. Production costs generally include operating, gathering and processing, well main-tenance, facility and equipment costs, direct administrative expenses and production taxes. They can varygreatly depending on the type of reserves being produced and the efficiency of a companys operations. Pro-duction costs are particularly important in assessing a companys cash realizations and ability to produce prof-itably in a given price environment.

Full Cycle Costs per BOE: Total full-cycle analysis considers all the cash costs required to produce and sella companys reserves as well as the costs (albeit historical) of finding and developing new reserves to replacethose produced. It puts the total cash costs of finding, developing and producing reserves on a comparableunit cost basis and can be viewed as a reasonable proxy for a break-even price analysis. In general, lower totalfull-cycle costs are viewed as a credit positive because they usually result in higher profits and cash flow andprovide a company with greater flexibility during periods of weak commodity prices. The full cycle cost perBOE sums the 3-year average F&D costs (all sources) per BOE with total cash costs per BOE. These cashcosts include production or lifting costs, cash G&A costs (i.e. adjusted for any capitalized amounts), grossinterest expense and preferred dividends. We evaluate total cash costs on an unleveraged basis before interestand preferred dividends, which excludes the impact of capital structure, and on a leveraged basis after interestand preferred dividends. Whenever possible, reported company numbers are adjusted to eliminate differencesthat may arise due to different accounting methods or classifications of certain costs to make analysis compa-rable across the peer group. This analysis does not factor in the impact of differences in price realizations,which can often cause cash margins (revenues less cash costs) to vary materially from one company to another.However, that is captured in our recycle ratio analysis.

Recycle Ratio:The recycle ratio incorporates revenues and cost structure to show on a unit basis how muchcash a company generates in excess of its costs of replacing reserves, which would be available for furtherinvestment in growth. It is calculated by dividing a companys cash margin per BOE (production revenues lesscash costs including interest expense) in a given year by its 3-year average F&D costs (all sources), to giveeffect to a full investment cycle. In evaluating cost structures, the ratio reflects the differences in price realiza-tions among companies, which can be substantial. As noted earlier, the price a company receives for its oil andgas production often varies depending on location, specific product characteristics, and hedging. Productioncan either be sold at the well-head (i.e. before incurring transportation costs) or at certain hubs (i.e. HenryHub or AECO). Geographic location may also impact realized prices, as international production is oftensubject to some type of PSC/PSA or other pricing mechanism. While this ratio factors in differences in pricerealizations, it is also clearly affected by commodity price levels. Therefore, this ratio can be quite meaningfulwhen analyzed through commodity price cycles. In general, a recycle ratio that remains above 1.0x duringperiods of weak commodity prices is viewed positively. We have attached a sample chart (using EOGResources) that provides an overview of the reserve and production statistics, operating and cash flow num-bers, and full cycle cost structure analysis for our analysis of independent E&P companies.


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Refining and M arket ing Analysis

Analysis of refining and marketing operations requires a long-term view since margins tend to be highly volatile and

can cause wide swings in a companys financial performance from quarter to quarter. Periodic shutdowns for mainte-nance or turnarounds can also hurt throughput and capacity utilization. Refining margins are affected by macro factorsoutside the companys control such as supply and demand relationships and feedstock costs. To analyze a refiner welook at its crude slate and feedstock access, system configuration and complexity, cost structure and product yield, aswell as its location, size, competitive market position, and other factors. In marketing, we look at the linkage between acompanys refineries, distribution channels and retail outlets, its retail market share, whether its wholesale markets areproduct long or short, and its marketing strategies.

KEY QUALITATIVE ISSUES Geographic Diversification: In the 1990s, many refiner/marketers pursued a strategy of geographic region-

alization and concentration to reduce costs and enhance profits and market position. Despite this trend,industry consolidation has resulted in large market shares across numerous regions for the large integrateds.Some of the surviving independent refiner/marketers such as Marathon Ashland and Sunoco have remainedmore regionally focused, whereas others such as Valero and Tesoro have become more geographically diversi-fied via acquisitions. A geographically diverse spread of refining and marketing assets can have a positive port-

Lighter

Heavier

ProductsFeed Stock Fractionation Upgrading/Processing

Fuel Gas

LiquifiedPetroleum Gas

ChemicalFeedstocks

Motor Gasoline

Jet Fuel

Diesel Fuel

Heating Oil

LightGasoline

Naphtha

Kerosene

Diesel

Reformer

Light GasOil

Heated

CrudeOil

Heavy GasOil

FluidCatalyticCracker

AlkylationPlant

AviationGasoline

Coker

PetroleumCoke

Residuum

AsphaltFuel Oils

LubricationOils

DistillationColumn

Blending

HydroCracker

Lube OilHydroCracker

Refinery Schematic


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folio benefit for refiner credit ratings. Exposure to seasonality, different margin characteristics, unplannedrefinery outages, and other factors varies from market to market and across national boundaries.

Refinery Size:Size per se is not a virtue or a guarantee of acceptable returns in an over-capitalized industry.

However, refining is a volume driven business with a large fixed-cost component. A larger 200,000 bpd refin-ery can benefit from economies of scale to lower unit costs and is more likely to be the efficient survivor thana 50,000 bpd unit, particularly under the burden of non-productive environmental costs. The most-used mea-sure of refining capacity is barrels per day of crude distillation capacity, which measures first stage treatmentof crude inputs. A refinery may have numerous other upgrading units that run distilled crude fractions and aremore relevant to determining its product slate and profitability.

Refinery Configuration and Complexity:A refinerys crude diet will depend on its configuration andcomplexity, or the number of different operations it performs to yield higher value products. (See RefinerySchematic Chart.) A simple crude distillation refinery generally needs more expensive light crudes (30-34degree API gravity) to produce an acceptable light product yield of about 70% gasoline, diesel and jet fuel.The more complex processes such as hydrocracking, coking, reforming, and alkylation transform or upgradethe carbon molecule. These processes enable a refinery to run lower-cost heavy sour crudes and still producea high value product slate, minimizing low value ends (residual). Complex refineries are also more expensive

to build and have higher capital costs to recover. Medium and highly complex refineries (deep conversionrefineries) typically produce 70-85% gasoline and jet fuel.

Refinery Reliability:Plant reliability has a very major impact on refining costs and profitability, and industryaccidents and downtime tend to increase during periods of high utilization and cost cutting. Reliability is afunction of equipment age, complexity, company maintenance and safety policies, and ongoing capital invest-ment. Indicators of reliability and operating expertise include utilization rates at the plant level, the frequencyof unscheduled turnarounds and major or minor mishaps, and managements track record on restoring opera-tions after interruptions and accidents.

Crude Slate: Crude feedstocks accounting for more than 80% of a refiners barrel of product cost. A refin-erys optimal crude slate is largely determined by its complexity and location. In assessing a refinerys coststructure and competitive position, we look at its typical crude diet, light or heavy (gravity), sweet or sour (sul-fur content) and the availability of supplies. A consistent and predictable crude slate enhances operating effi-ciency and product reliability. A flexible refining configuration and balanced mix of lighter and heavier crudes

also allow a refiner to take advantage of changing price differentials between crudes. Many of the U.S. refinershave invested in cracking and coking capacity based on a trend in heavier crude supplies and a longer termexpectation of widening light/heavy crude differentials. Light/heavy differentials change frequently based onthe relative supplies of crude on the market.

Inventory Management:Management of crude and product inventories has a direct effect on financial per-formance. A refiner that can minimize the time lag between crude pricing, delivery, processing and productdelivery can reduce working capital needs and exposure to inventory losses and adverse product price move-ments. This problem can be most acute in a declining crude price environment, when a refiner has purchasedcrude and built inventories at higher prices and can experience from 20-40 days lag between crude purchaseand product delivery to the market.

Logistics and Location: Product supply and distribution channels have a major impact on refiners coststructure, profitability and competitive advantages. Supply and distribution configurations are typically com-plex, comprising pipelines, ships/barges, trains, trucks, and crude and product storage terminals. The refiners

goal is to minimize transportation costs, ensure safety and dependability, and access the most attractive mar-kets. Branded retail and branded wholesale markets typically offer higher margins than unbranded wholesaleand spot markets. Refinery location (land-locked, on a river, near ports) not only affects market access, butalso affects transportation costs, access to crude supplies, and energy costs. Proprietary pipelines or access tothird party capacity can be particularly important to refiners in regions with excess supplies seeking higher-return markets. Certain geographic markets or niche players can also have differential margin advantages. Forexample, in California refining margins tend to be higher due to strong year-round demand for gasoline,unique fuel specifications to satisfy environmental regulations, and limited competition from pipelines andproduct imports.

Downstream Integration: Refiners invest in service stations and linked convenience stores to capture maxi-mum value-added. Retail operations can offset volatile wholesale product margins, since gasoline margins fre-quently (but not always) increase when wholesale margins are under pressure. Retail integration is particularlybeneficial in highly competitive and over-supplied markets (e.g. the U.S. Gulf Coast) since it helps place

products and maintain market share. Most major participants emphasize high volume, upgraded stations in


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Crude Self-Sufficiency: For integrated companies, crude self-sufficiency measures the degree to which arefiner can obtain crude from internal upstream sources, (upstream crude produced as a percentage of down-stream crude volume requirements). A higher degree of self-sufficiency would generally indicate more valueadded and enhanced profitability. While a high degree of crude self sufficiency can be viewed as a positive, ithas become less crucial in light of plentiful crude supplies, sophisticated trading capabilities and product swaparrangements.

Refinery Margin per Barrel of Output: Companies often do not publicize unit refining margins and cashoperating costs because of competitive concerns. When they do, the methods used to calculate refining andretail margins can vary, making comparisons difficult. However, when available, we compare gross margins(product revenues less crude costs) per unit of product output among companies and against an appropriateindustry benchmark such as the 3-2-1 crack spread or the 4-2-1 heavy crack spread.

Product Slate:Product slate is the mix of a refinerys end products such as gasoline, jet fuel, middle distillates(diesel) and heavy ends, usually broken down on a percentage basis. Generally, the higher a refinerys yield ofgasoline and light ends, which command a premium, the more profitable it should be. A highly complex refin-ery can produce 75-85% light products. However, margins are affected by industry inventory levels anddemand. Refinery configuration and product slate should ultimately be geared to the market served in order

to efficiently clear product and avoid disposing of excess supplies at a discount. Retail Market Share:A companys share of product volumes and service stations can indicate market cloutand the ability to move product, but does not necessarily correlate with profitability. Market share can bemeasured within a companys own market area or in the context of a larger (e.g. national) scale. A majorretailer such as Shell or BP can have a 20% share in selected local markets in the U.S. or national markets inEurope or Asia, and will compete head on with large regional independents, hypermarkets, and other partici-pants for major stakes in a national market.

Refined Product Integration:This ratio measures a refiners own product self sufficiency, or output as apercentage of product sales (refined product output/total sales volumes). In theory, the more internal produc-tion, the higher the profitability, although trading capabilities and surplus inventories reduce this advantage.Most larger refiner/marketers are net buyers of refined product to sell through their systems.

Throughput per Outlet:Gallonage sold per retail station is an important measure of efficiency. Generally,higher volume stations in prime urban locations can sell upwards of 200,000 gallons per month and are more

desirable and profitable. Small rural markets sometimes can enjoy high margins, but typically throughput islighter and they bear high transportation and servicing costs. Industry restructuring has focused on eliminat-ing small volume rural or urban stations that have high costs and low volumes.

Financial Analysis Key M easures and Rat ios

CASH FLOW PROTECTIONCash flow from operations is the most important measure of a companys real debt protection capabilities. Our pri-mary focus in cash flow analysis is the adequacy of cash flow support for debt protection, funding of capital spendingand dividends, and generation of free cash flow. Our goal is to try to assess the downside risks to cash flow and kktoderive a reasonable projection of cash flow protection to arrive at an appropriate credit rating.

These measures include gross cash flow (GCF) from operations, retained cash flow (RCF), which deducts divi-dends from gross cash flow, and free or discretionary cash flow. These measures are all adjusted for non-recurringitems such as gains or losses on asset sales. It should also be noted that debt includes more than just the on balancesheet long-term and short-term debt obligations. As is discussed later, the debt number we use is adjusted to reflect acompanys true financial leverage, incorporating, for example, hybrid instruments and preferred stock, as well as off-balance-sheet obligations such as operating leases, accounts receivable financings, unfunded pension liabilities, andguarantees. Retained cash flow analysis treats dividends as a quasi-fixed charge, based on the view companies generallywill only cut dividends in dire circumstances. Free cash flow is the cash flow available for debt reduction and discre-tionary uses such as opportunistic growth projects or share repurchases after the funding of dividends and base levelcapital expenditures. The primary cash flow ratios we look at are:

GCF/Total Debt:a debt protection measure that shows how quickly a company could theoretically pay offall its debt from internal cash flow.

RCF/Total Debt:a more stringent and realistic starting point for cash flow analysis, since dividends for mostinvestment grade companies are a form of fixed charge that are rarely cut except in dire financial circum-stances.


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Free Cash Flow/Total Debt: residual cash flow protection for debt service after funding of dividends andmaintenance capital.

GCF/Capex: a measure of a companys ability to fund its capital spending from internal cash flow.

RCF/Capex: internal funding of capital spending after dividends have been serviced. DD&A/Capex: the level of reinvestment of amortized capital; over time, a company should be reinvesting

equal to or in excess of its DD&A.

The definition of maintenance capital spending can vary. It generally includes basic maintenance projects, envi-ronmental clean-up or prevention programs, and sometimes key capital investments necessary to maintain or improvea companys competitive position. Since the industrys chief challenge is asset depletion, maintenance capital includescore spending necessary to replace reserves. (In reality, stronger companies with deeper reserve bases can cut theseinvestments during periods of stress without permanent impairment.) In the petroleum industry, maintenance spend-ing should also include future contractual spending commitments, which are prevalent via partnership arrangementsand long-term supply relationships. A useful, albeit simplistic, proxy for maintenance capital needed to replace 100%of production is to multiply a companys F&D costs (e.g. three year average) by annualized BOE production. Forexample, a company with F&D costs of $4.50/barrel and annual production of 100 million BOE would have to spend$450 million per annum to maintain its reserve base ($4.50 X 100 MM BOE = $450 MM).

Larger integrated oil companies typically have a greater capacity than other industry participants to internallyfund capital spending. Fair amounts of non-core asset sales also routinely supplement operating cash flow for thesemature diversified companies. However, large dividend payouts are also the norm, often in excess of 50% of earnings,and contributing to a need to finance. Large acquisitions, multi-year capital projects, and share repurchases also cancontribute to rising financial leverage.

Cash flow for independent E&P companies and refiner/marketers tends to be more volatile. E&P cash flows areexposed to fluctuating commodity prices and large investments to replace reserves, and the impact of capital curtail-ments can be more severe for an independent than for an integrated major. The refining and marketing industry ben-efits from cyclical periods of free cash generation and can more readily curtail discretionary growth projects withoutpermanent impairment. Nevertheless, volatile margins and mandated capital can hurt earnings and absorb free cashflow, as happened in the mid-1990s when the industry made major investments for clean fuels and other environmen-tal mandates. We believe price risk and high capital requirements make high dividend payouts and share repurchaseprograms unadvisable for independent E&P companies, and generally negative credit events both for debt protection

and for future growth.

CAPITAL SPENDING ANALYSISCapital spending analysis is helpful in understanding a companys operating strategies, growth plans, and areas ofunder-investment and de-capitalization. More than two-thirds of the petroleum industrys capital spending is investedin the upstream sector. Refining, marketing and chemicals are also capital intensive and subject to cyclical spendingpatterns.

For petroleum companies, capital spending issues to analyze include:

Spending by geographic and business sector, concentration or diversification, and political risk.

Trends in exploration and development spending, including maintenance levels, as indicators of futurereserve replacement and long-term production growth.

Maintenance capital needed to replace reserves and maintain plant and equipment for safety and effi-ciency. In the downstream, maintenance of plant and environmental outlays are generally non-discre-tionary and should be factored into base capital spending.

Major long-term projects: what levels of capital are committed and possibly beyond the companys con-trol as to timing? Are such projects vulnerable to political disruption or sensitive to changes in the eco-nomic/pricing environment and changing market conditions?

Changing environmental or other regulatory events that may result in increased mandatory investment.

FINANCIAL RETURNS AND QUALITY OF EARNINGSWhile cash flow is of primary importance for debt holder protection, financial returns are key to a companys ability toattract future capital for investment and thus to maintain or improve its long-term financial health. We analyze thecontributions of a companys various business segments to operating and net income and their shares of total revenues,assets, and capital spending. Segment cash flow and capital spending analysis reveals which portions of a companys


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operations are generating free cash to support reinvestment in other areas and which operations are consuming cash.Segment operating returns can also point up vulnerability to restructuring and asset writedowns, as well as industrypressure points and trends.

Return on capital employed (ROCE) is one of the industrys most widely used return benchmarks, both for oper-ating divisions and the consolidated company. We also look at pre-tax return on capital as an indicator of operatingreturn on debt and equity. Other important return measures include operating and net return on sales (ROS), returnon assets (ROA), and return on equity (ROE). ROS and ROA are useful for high revenue, capital intensive portions ofthe operations such as refining and marketing. Most of the majors view a 12-15% ROCE as an acceptable capitalreturn on a mid-cycle basis, recognizing that they can be higher or lower depending on the cycle. Despite rigorousstreamlining and cost reductions, this target has proved difficult to achieve on a sustainable basis due to depressedupstream pricing and the capital tied up in downstream operations. The R&M sector typically has returned no morethan a 5%-6% return on capital compared to significantly higher upstream returns, which explains the industrysongoing efforts to joint-venture and rationalize their R&M operations.

Quality of earnings and comparability of peer group companies is also an issue due to accounting variations andthe impact of non-recurring events. We adjust for these items, as necessary, to get a truer picture of operating earnings,net income, and fixed charge protection. Some of the more common factors that can affect reported returns in the

petroleum industry are: Full Cost vs. Successful Efforts Accounting:These two accounting methods affect a companys reported

exploration expense and earnings and the capitalized value of its oil and gas operations, mainly due to differ-ences in the treatment of dry holes, or the expenses related to unsuccessful wells. Under successful efforts,only expenses related to successful commercial wells are capitalized, while dry holes are expensed againstearnings when incurred. The full cost method capitalizes dry holes and amortizes them against all futureproduction. In effect, it treats dry holes as part of the full cycle of costs needed to bring successful wellsonstream. Other costs incurred also are capitalized, including interest costs and certain components of SG&Athat would be expensed under Successful Efforts. Successful efforts can lead to more volatile earnings. Fullcost tends to overstate the balance sheet valuation of reserves and equity as reported earnings build up. Thetwo methods should be cash flow neutral over time, since a more steady earnings profile under full cost tendsto be offset by higher DD&A on the cash flow statement. From a credit perspective, successful efforts is moreconservative, or closer to economic reality, vis-a-vis earnings, asset capitalization, and book equity, since dry

wells are written off up front. All of the integrated petroleum companies and many of the larger independentsuse successful efforts, although it should be noted that three of the largest E&Ps, Anadarko Petroleum,Apache, and Devon Energy, use Full Cost. Proponents of full cost tend to be smaller E&P companies less ableto withstand volatile earnings gyrations.

Inventory Accounting:Last-in-First-out (LIFO) inventory accounting is used by virtually all the larger inte-grated and independent refining companies. In LIFO accounting, a company books its crude inventory pur-chases using the most recent crude price. During periods of crude price volatility, the time lag betweenfeedstock purchases and the sale of the refined products causes profits to be understated when crude costs rise,and overstated when crude prices fall faster than product prices. Regardless of method, the cash costs of pur-chasing and carrying crude oil are the same. LIFO also means that inventory carrying values can be underval-ued on the balance sheet (the LIFO Cushion), particularly for long-established companies that carry manylayers of cheap oil on their balance sheet. Costing through or drawing down these older low priced layerscan lead to inventory profits without any real impact on cash flow.

Tax Issues:Companies in different locales may be subject to different corporate tax rates and other taxes lev-ied on the industry. Statutory tax rates may differ dramatically from cash taxes paid depending on spendinglevels and tax deferrals, as well as differing foreign tax credit and tax loss carry forward positions.

Non-recurring Charges/Gains:The petroleum industry is prone to one-time charges or gains that canmask a companys underlying operating performance. Major sources of such charges, which may or may nothave a cash impact, include reserve sales and ceiling test writedowns; the restructuring or sale of under-per-forming refining and chemical assets; personnel reductions and associated severance programs; and exits fromnon-core businesses such as coal and metals. We look at the cash impact of the charges on reported earningsand cash flow.

Impairment/Ceiling Test Writedowns: For companies following successful efforts accounting, FAS 144prescribes procedures for assessing impairments in the value of long-lived assets. For the petroleum industry,the rules primary impact is on reserves, which can be written down during periods of price volatility. Theimpairment test is performed at the lowest identifiable asset unit, in this case typically at the oil field level. It

begins by comparing the estimated undiscounted future cash flows to the book value of the assets. If those


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cash flows are less than book value, the assets are impaired. Alternatively, if the undiscounted future cash flowsexceed the book value of the asset, then no impairment is recognized, even if the fair value of the assets is lessthan the book value. Once an asset (a field) is determined to be impaired, a charge is taken against income towritedown the assets to their fair value, reducing reported earnings and book equity. For companies followingfull cost accounting, the rules for assessing reserve impairment are included in SEC Regulation S-X, Rule 4-10. Each quarter, companies are required to estimate the discounted future cash flows for each full cost pool(usually all reserves held in a particular country) using current period-end oil and gas prices and a 10% dis-count rate. This ceiling amount is compared to the book value of the full cost pool and if the ceiling islower, the full cost pool is written down to the ceiling amount, resulting in a charge to income.

These impairments contribute to reported earnings volatility but can serve as a valuable reality check on overval-ued assets. Overtime they also can mask bad investment decisions (e.g. inflated acquisitions) and provide a quick fix forpoor capital returns. The writedowns can also be somewhat punitive on economic values. Once reserves are writtendown, they cannot be written back up even if the price decline proves to be temporary and the reserves will be produc-ing for many years. In general, these non-cash writedowns do not affect credit ratings, although they can be indicatorsof potentially serious financial stress or can trigger liquidity problems, particularly for smaller capitalization companiesthat have borrowing bases in their bank loan agreements.

FINANCIAL LEVERAGE AND BALANCE SHEET ANALYSISAs noted, traditional leverage ratios such as Total Debt/Equity and Total Debt/Total Capitalization are merely startingpoints in assessing a petroleum companys financial leverage. These ratios in isolation can be unsatisfactory leverageindicators since the capitalized value of property, plant and equipment and book equity values do not reflect currentpricing or the true underlying value of oil and gas reserves in the ground. Moreover, in the downstream, the depreci-ated value of refining and petrochemical plants often does not reflect replacement value.

To get a better picture of leverage, we look at a companys cash flow protection relative to debt, focusing on cur-rent operating cash flows and on the discounted SEC NPV of reserves. Segment operating results and capital returnscan also point up weaknesses in asset and equity values, which are adjusted accordingly. Large integrated companieswith diversified cash flows can bear more debt than smaller independent E&Ps or refiners. However, volatile com-modity prices, significant capital requirements and the need to maintain financial flexibility for late breaking businessopportunities have shown that elevated financial leverage does not benefit any of these industry sectors.

With regard to market capitalization, we do not usually incorporate stock price valuations into our assessment ofdebt holder protection. However, we do look at a companys market valuation as a check relative to its book financialleverage, as well as a significant indicator of market pressures that could motivate management to use stock as currencyin acquisitions or to repurchase stock, and thus as a reflection of its financial flexibility.

Off-Balance-Sheet Financing: Off balance sheet liabilities must also be factored into financial leverage and areincorporated into our adjusted total debt calculations. These liabilities are becoming more significant in the industry ascompanies enter into project financings and other forms of joint-ventures and alliances that incur their own direct debtobligations. We do not take a formulaic approach to these liabilities. The key questions revolve around materiality,strategic importance of the investment, and whether such financings should be treated as a use of the parents debtcapacity, which can range from zero to 100%, depending on the type of financing and the reasons it is undertaken.

One example of off-balance-sheet financing is operating and synthetic leases, which are commonly used to financeservice station networks, drilling rigs, and other assets. We typically treat these leases as a use of debt capacity sinceretailing is a core business and the leases are intrinsic to the way most of the companies finance their service stations.For operating leases, we try to estimate the present value of the future lease payments or, for shorthand calculation,will assign a multiple (usually 8 times) to the average annual lease payments. That amount is added to balance sheetdebt to determine adjusted leverage. Other liabilities include throughput and deficiency obligations on pipeline sub-sidiary debt, where the parent must supply a pro-rata share of throughput or cash payments sufficient to generate pipe-line revenues for debt service.

Line item treatment of unconsolidated equity investments (including joint ventures and project financings) canoften mask large subsidiary financial obligations that may or may not make some implied call on parent company sup-port. Certain forms of performance, completion and financial guarantees are disclosed in footnotes but are notreflected on the balance sheet. Large project financings, structured to be legally non-recourse to their sponsors, canhave substantial pre-completion supports such as unlimited completion guarantees or strategic significance thatimplies continued sponsor support in difficult circumstances. All of these need to be analyzed on a case by case basis,with appropriate adjustments to financial leverage and for peer group comparability.


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LEGAL STRUCTURE AND COVENANTSMoodys long-term debt and preferred stock ratings are applied to specific securities issues, based on our fundamentalview of a companys senior unsecured credit quality and reflecting the legal position of a specific security and creditor

within the companys capital structure. In rating securities, we place particular emphasis on covenants that affect cashflow movement between an issuing entity and its various affiliates (dividend restrictions, limitations on subsidiary debtissuance) and on the investors clear access to that cash flow. Also of considerable importance are restrictions on secu-rity interests and an issuing entitys ability to pledge assets or cash flow, which could disadvantage existing investors.

In practice, most investment grade petroleum companies have very broadly crafted covenant protections in theirpublic debt that provide wide flexibility and few restrictions that protect bondholders (perhaps debt incurrence, mini-mum tangible net worth, etc.) Low investment grade and high yield companies with more limited financial flexibilitytend to have more classes of securities with a wider spread of ratings, reflecting the increased risk of default and differ-ing classes of creditors. Reserve-based lending facilities and security interests in reserves or other assets also becomemore significant in assessing debt holder protection. In reserve based lending, access to bank funds is based on com-modity pricing and other assumptions that are periodically reviewed and determined by lenders. Thus, changes incommodity prices can adversely affect a companys liquidity and ability to fund its operations. Regarding security, banklenders often have a senior position and secured interest in the companys assets. We assess the value of the security,

usually notching up the ratings on secured debt above other unsecured or subordinated creditors.

FINANCIAL FLEXIBILITY AND LIQUIDITYMoodys analysis of financial flexibility focuses on the companys ability to generate cash under stress scenarios andmaintain sufficient liquidity to meet maturing debt obligations in a timely manner. We do not generally rely on stan-dard liquidity ratios since they are static in nature and often have limited value. To take an extreme case, a companymight have sufficient cash available to meet near-term maturing obligations but could still default if its Board projecteda serious cash flow deficit in six months and decided to declare bankruptcy to conserve resources and pressure creditorsto re-negotiate their agreements.

In assessing liquidity we look at the companys liability structure: are short near-term and long-term maturitieswell placed and appropriate to the companys cash flow profile? Does the company face large debt maturities in a shorttime frame? The petroleum business and oil pricing historically have been viewed to have something of a naturalhedge against rising interest rates because of the strong correlation between oil prices and inflation. Nevertheless,most petroleum companies want to mitigate interest rate risk and avoid rollover risk, managing their balance sheetssomewhere in the 30-50% fixed range. We also look at whether a companys cash or marketable securities are readilyconverted into cash. We evaluate the quality, maturity and liquidity of the securities, the companys normal operatingcash position, and possible currency exchange losses or tax consequences that could be impediments to quickly con-verting securities to cash.

Another key liquidity component is the reliability of an issuers borrowing power under stress scenarios: thestrength of contractual lending commitments (committed bank agreements vs. uncompensated credit lines), the qual-ity of the lending institutions, and the history and strength of a companys banking relationships. Alternate liquidity iscritical in rating commercial paper because of the instruments short maturity profile and the inability of even highlyrated companies to repay maturing commercial paper on short notice from internally generated cash. Our alternativeliquidity evaluation is based on a one-year time horizon and assumes loss of access to the commercial paper market in astressful but plausible scenario of market turbulence and general illiquidity.

Qual i ty of M anagement

The quality of a companys management is one the most important and difficult to quantify factors in the credit rat-ing process. Our assessment of managements abilities and risk appetite can often be the deciding factor in a rating.Management controls all the internal elements central to a companys credit quality, including most importantly, thecompanys risk appetite, controls, leverage targets, and philosophy on use of financial leverage and shareholderrewards. Management must also react to and deal with the larger industry environment outside its control. We evalu-ate managements track record, its strategies for future growth and core operations, and its financial policies and con-trol systems. The companys strategic direction should derive from managements views of the larger businessenvironment and where it sees the companys strengths and weaknesses. Implicit in this is managements appetite forbusiness/operating risk and financial risk. We have attached as an addendum a brief summary of the more importantissues we examine and questions we ask in evaluating management.


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Even t Risk

A final consideration is the possibility that a special event could cause a sudden and sharp decline in an issuers funda-

mental creditworthiness. Special events have an unavoidable element of surprise because their precise timing, nature,and impact on a companys creditors cannot be predicted in advance by the tools of fundamental credit analysis. Typi-cal special events are mergers and acquisitions, capital restructuring programs such as large share repurchases and, atthe extreme, leveraged buy-outs. For commodity-based industries, prolonged periods of price weakness often forceindustry consolidation and increase the probability of event risk. Low upstream pricing and weak downstream returnswere the impetus for much of the merger activity in the late 1990s, which extended to the integrateds, refiner/market-ers and independent E&Ps.

Event risk tends to affect a companys credit fundamentals most significantly when it involves a major change incompany management or a dramatic increase in debt leverage. Most recent mergers have not resulted in downgradeslargely because of the potential cost savings, enhanced asset bases and market position, and generally conservativeequity financing involved. Large debt-financed reserve acquisitions frequently result in downgrades since high fixedcharges and reduced financial flexibility are incompatible with volatile commodity prices and cash flows. Over the pastdecade, environmental and other litigation and major industrial accidents have resulted in a few special events, creating

large unexpected claims and cash payments against an issuer. We examine these events on a case-by-case basis. Whenlitigation is involved, we try to determine possible outcomes, looking at the companys liquidity and financial reserves,as well as its ability to sustain large cash outflows and maintain financial flexibility. To a certain extent, share repur-chases can be viewed as a predictable event, in which case we try to look at the market forces motivating the repur-chases and managements own appetite for shareholder rewards.

Conclusion

Moodys credit ratings for petroleum companies synthesize a companys financial and operating profile and our expec-tation for future performance and debt protection measures in light of specific company and industry risks. Our analy-sis starts with company cash flow and balance sheet analysis historical and projected and is expanded to includesignificant underlying petroleum reserve and production valuations and trends derived outside the financial state-ments. The need to incorporate reserve analysis is based on the fact that depletion of the petroleum resource base

makes reliance on historical results misleading and possibly irrelevant. Petroleum exploration and production entailsignificant geological and other risks, with large ongoing investment to offset depletion. In addition, a companys nom-inal balance sheet values do not reflect the underlying value of reserves in the ground, or their future cash flow andprofit potential since reserve values change constantly with market changes in commodity pricing.

Related Research:

Special Comment:

Oil & Gas Industry Update, November 2003, #80027

Leveraged Finance Industry Updates: Gas and Oil, June 2003, #78434

Goodwill Accounting in the Oil Patch, December 2002, #77044

Industry Outlook:

Integrated Oil Industry Study, October 2003, #79843

Rating Methodology

Moodys Approach to Assessing Key Credit Measures for Investment Grade E&P Companies, February 2003, #77114

Increased Environmental Compliance Spending, December 2002, #76889

To access any of these reports, click on the entry above. Note that these references are current as of the date of publication of thisreport and that more recent reports may be available. All research may not be available to all clients.


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Selected Petroleum Industry Terminology

Proved Reserves:Reserves discovered and classified as proved indicate reasonable certainty of volumes, development

and recovery under reasonable pricing assumptions and identified technology. Usually certified by independentreserve engineers. For conservative fixed income analysis, we generally give credit only to proved reserves. Two reservecategories of less certainty, probable and possible, can also be disclosed.

BOE Reserves: Oil, natural gas, and gas liquids reserves translated into energy equivalent barrels. Natural gas istranslated on an energy equivalent basis at 6,000 BTU: 1 barrel of oil. (For some natural gas producers, can beexpressed in billion cubic feet equivalents i.e. BCFE.)

Oil/Natural Gas Mix: Percentage breakout of oil, natural gas and gas liquids in reserves and production stream.Important to understanding the sensitivity of earnings and cash flow to commodity prices.

Production Profile:Cash flow and growth prospects. Rate of projected production from a companys combined fieldsover some period of years (3, 5, 10 years). Generally disclosed by company. Subject to many variables, so need to exam-ine assumptions and levels of certainty around projection.

Reserve Life Index (RLI):Measures cash flow/asset protection. The number of years a company could produce itsreserves at current rates

moody's approach to rating the petroleum industry (2003).pdf

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