Rating Methodology. Summary. December 2003

Transcription

1 Rating Methodology December 2003 Contact Phone New York Thomas S. Coleman John Diaz John Cassidy Alexandra Parker Andrew Oram Kenneth Austin London Jeremy Hawes Sydney Terry Fanous Tokyo Junichi Yamaki Hong Kong Michelle Toh Singapore Chris Maynes Moody s Approach to Rating the Petroleum Industry This 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. Summary Moody s approach to rating petroleum companies starts from much the same point as other industrial companies. We analyze historical cash flow protection, financial performance, and operating trends to place a company in the context of its peer group and broader industry conditions. Historical markers, however, are just the starting point: the primary function 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 and improved line of products every year as long as it has access to labor and materials. An oil and gas company s reserve base is finite and depletes with every barrel produced. To be successful, a petroleum company must reinvest substantial capital year after year to find new reserves and replace production. Exploration success and reserve replacement have a large element of geological risk but are also linked to companies locations, core legacy positions, and technological advantages. While financial results and ratios are important to credit rankings, an oil and gas company s record and future prospects are not effectively or most directly captured in its income statement, cash flow, and balance sheet. To arrive at a more meaningful assessment of cash flow, asset protection and financial leverage, we look at a variety of petroleum reserve 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 operating efficiency, elements within a company s control, as critical indicators of its ability to operate and service debt in difficult pricing and margin environments. Finally, because of commodity price risk and high capital reinvestment risk, petroleum companies cannot bear the elevated financial leverage typical of a more stable cash generator such as a regulated utility. The higher the financial leverage, the lower rated a company is likely to be. For the same reason, larger integrated companies with more diversified cash flow and often countercyclical upstream and downstream operations are the highest rated companies in the petroleum universe, while exploration and production companies, which lack the level of reserve diversification and downstream integration, are more exposed to price risk and reserve success and are rated lower.

2 Table of Contents Introduction...3 Rating Process...3 Petroleum Industry Structure And Fundamental Risks...4 Industry Structure...4 Industry Fundamentals...5 Moody s Approach To Commodity Price Risk...6 Sovereign And Regulatory Risks...6 Upstream Operations And Petroleum Reserves...7 Reserve Analysis Some Qualitative Issues...7 Asset Protection And Reserve Leverage Key Metrics...8 Operating Success And Cost Structure Refining And Marketing Analysis Key Qualitative Issues Quantitative Measures Financial Analysis Key Measures and Ratios Cash Flow Protection Capital Spending Analysis Financial Returns And Quality Of Earnings Financial Leverage And Balance Sheet Analysis Legal Structure And Covenants Financial Flexibility And Liquidity Quality Of Management Event Risk Conclusion Other Related Research: Evaluating Management a Brief Checklist Selected Petroleum Industry Terminology Sample Integrated Oil Credit Statistics Sample Independent Exploration and Production Credit Statistics EOG Resources, Inc Sample Independent R&M Credit Statistics Moody s Rating Methodology

3 Introduction RATING PROCESS Moody s credit rating process for petroleum companies follows a systematic approach similar to other industrial company analysis: we take a top down and bottom-up approach, starting with the macro-economic picture (broad political, economic, and industry environment), moving to an assessment of the company s operating and competitive position, and ending with its financial position and strategy. A company s financial statements, footnotes, and ratios are important to the process, supplying information to measure its health and ability to grow and providing a basis for comparison with its peers. However, they are only part of the picture. Numbers as presented can be manipulated and subject to different accounting treatments. Therefore, we look for ways to adjust financial statements and ratios to reflect a company s true underlying risks and what we believe to be its true economic worth. Analysis of the petroleum industry also involves a set of specialized petroleum reserve and production measures intended to capture information not adequately reflected in an oil company s 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 operating trends, cash flow, earnings and balance sheets. Key determinants of a rating are the volatility of a company s cash flow and underlying debt coverages relative to the risks undertaken and to the company s peer group. Moody's Rating Analysis Pyramid Rating Qualitative Analysis Management Strategic Direction Financial Flexibility Quantitative Analysis Financial Statements Past Performance Future Performance Market Position Competitive Trends in Sector Global/Domestic Regulatory Environment Global/Domestic Sectoral (Industry) Analysis Sovereign Macroeconomic Analysis Moody s Rating Methodology 3

4 Petroleum Industry Structure and Fundamental Risks Structure of the Oil Industry UPSTREAM Exploration Production DOWNSTREAM Refining Gas Processing Chemicals Transportation Marketing Coal INDUSTRY STRUCTURE The 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 natural gas 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 of gas 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 operating characteristics and credit profiles: The integrated majors engage in all phases of the business from petroleum exploration to refining and retail sales at the gasoline pump. The majors by virtue of their large natural gas and capital resources are the prime movers in a growing international liquefied natural gas (LNG) business on both the supply and receiving end. Many also have extensive petrochemical operations. For them, petroleum is truly a global industry characterized by scale, geographic diversification, and upstream and downstream counter-cyclical benefits that help stabilize cash flow. The integrateds are thus the most stable and highly rated companies in the industry, with an average rating of Aa3. Independent exploration and production (E&P) companies engage primarily in the exploration, development and sale 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 depleting reserves. 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 quality of 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 are rated 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 producers on the open market. The retail part of the business includes service stations networks and, increasingly, convenience stores and fast food outlets. Refining and marketing are capital intensive, high volume and revenue businesses. They are subject to thin margins and volatile price swings on crude inventories. Competitive pressures rarely support rich pricing at the pump for very long. The performance of small niche refiners can also be dominated by geographical or logistical 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. 4 Moody s Rating Methodology

5 Oil Price per barrel Petroleum Industry Peer Group Average Rating $35 $30 $25 $20 $15 $10 $5 $ Brent (Avg Annual) Refiners Integrated Majors Oil Service E&P Aaa 0 Aa1 1 Aa2 2 Aa3 3 A1 4 A2 5 A1 6 Baa1 7 Baa2 8 Baa3 9 B1 10 Average Rating INDUSTRY FUNDAMENTALS In 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 difficult due to high barriers to entry in the form of capital, technological and drilling expertise, and required international skills. All of the major integrated players are long-established companies, as are many of the largest independents, which have grown organically and through mergers and acquisitions. In an industry characterized by mergers and consolidations over the last two decades, the only significant new entrants have been national oil companies, who in many cases have formed their own E&P units or can parlay their country s resources into joint ventures with experienced explorers and developers. National oil companies have become savvy participants as well as head-to-head competitors with the major private sector companies in both the upstream 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 OPEC discipline, the emergence of large non-opec supplies, and industry competition. Consequently, economies of scale and cost competitiveness are critical to profitability. Natural gas, in contrast, is more regional in its production and sales patterns (except in liquefied form) since market penetration is limited by pipeline access and physical proximity. Natural gas prices are only somewhat de-linked from oil prices since they compete with fuel oil in certain North American industrial and power markets, and in international markets such and Europe 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 and successfully over a long-period of time to replace and grow its production base. Otherwise, its reserves and market value will dwindle and the company will eventually liquidate. Many of the majors and most of the investment grade E&Ps have core production concentrated in mature older basins in North America and the North Sea, and the challenge is to grow production, while maintaining a competitive cost structure. Furthermore, 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 difficult in the future, particularly for companies concentrated in these mature areas. Cyclicality: The petroleum industry is inherently cyclical, following global and regional patterns of economic growth and product demand and industry patterns of investment, surplus and shortage. We aim, as much as possible, to rate companies through the cycle, which means that at any given point in time a company s rating 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 and equity values, due to fluctuating commodity prices, reserve performance, cost escalation, and the inherent uncertainty in measuring reserves in the ground. Reserve quantification and valuation are part art and part science, and the value of reserves in the ground is subject to changing prices, technology, and skillful exploitation. To get a better picture of a petroleum company s asset values and financial leverage, we look at cash flow protection, but also at a variety of reserve and production based measures that focus on operating success, cost efficiency, leveraging of reserves, and net present value. Moody s Rating Methodology 5

6 MOODY S APPROACH TO COMMODITY PRICE RISK In order to rate through the cycle our ratings must take into account commodity price volatility and incorporate a normal 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 the low to mid-$20s/barrel range (WTI), but continue to stress test ratings in the range of $15-18/barrel. Natural gas prices 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 broad view on the probability that pricing will achieve those levels. This helps determine how well and for how long a company can function at the low end of the price range without serious impairment of credit quality. It also helps pinpoint those 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 projected production decline rates, product quality differentials, actual price realizations, and cost structure. This analysis also factors in the impact that lower pricing will have on a company s 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 maintain spending and add new reserves, and on proved undeveloped reserves that could become uneconomic at lower prices. A related consideration is the company s stance on hedging its commodity price risk. We look at how much of a company s production is hedged and management s strategic reasons for hedging. In general, companies do not hedge to enhance profits or fundamental competitive position. Investors buy oil and gas stocks as a commodity price play and companies do not want to give away the upside. Most companies hedge some portion of their production to dampen price volatility and improve cash flow predictability in order to support a base level of strategic capital spending, which typically would include a large component of committed expenditures. SOVEREIGN AND REGULATORY RISKS The petroleum industry is almost unique in its high visibility and the critical political and economic roles it plays wherever it operates. In many countries, particularly in emerging nations with limited economic and resource diversification, oil is regarded as the national patrimony. It is both a vehicle for economic development and employment and the government s primary source of wealth. This has implications for political risk, government intervention, the setting of national budgets, upstream and downstream regulation, and taxation. Moody s considers all of theses factors when assessing credit quality, and while some of them are more relevant to the large integrated oils, many independent E&Ps have significant exposures in developing countries that will increase as they pursue growth outside of North America 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 operate globally and must invest in a country over long periods to become established players and recover their costs. Sovereign analysis involves a country s macroeconomic and political framework, as well as some understanding of petroleum s importance to a country, the state s role in the industry, and the relationship between the national oil company and foreign investors. Sovereign risk issues and the role of the state also factor heavily into the credit ratings of most wholly-owed or partly privatized state oil companies in Europe, the former Soviet 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 production, ranging from equity ownership of reserves to production sharing contracts and fixed fee- per-barrel arrangements. These structures affect the economics of exploration and development and a company s profitability. They determine the relative attractiveness of competing investments as well as a country s ability to attract foreign investment. The actual structure of contract payment flows can also be a critical political risk element when a host country is under stress; e.g. whether a producer sells to or is directly reimbursed by the state 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 production 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 differential income taxes. Consequently, tax regimes and assumptions are integral to company drilling plans, field development economics, and reserve valuations. At the extreme, taxes can be a very real political risk since governments in distress use tax policy as an effective and relatively easy way to raise revenues, particularly in lieu of more radical forms of intervention such as expropriation and nationalization. 6 Moody s Rating Methodology

7 Regulation/Environmental Risk: Government regulation is prevalent in most parts of the industry, tending to 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 and water emissions, site remediation and regulation of product prices at the pump. In addition, government regulation in certain countries such as South Korea and China favors the domestic refining and marketing industry. This reflects the strategic importance of oil to national economies and can be a supportive factor in the ratings for these companies, with ratings that tend to be closely linked to the sovereign rating. In the upstream, many producers are environmentally constrained in key growth areas such as the deepwater Gulf of Mexico and the Rockies, and will also have to begin funding remediation and plugging and abandonment activities as mature North American and North Sea fields reach the end of their economic lives. These expenditures 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 allocated to environmental projects, annual cash environmental costs, and the adequacy of the financial reserves established on an ongoing basis or for specific large liabilities. We also examine whether environmental outlays and related legal judgments could become reimbursable under company insurance coverages. Upstream Operations and Petroleum Reserves Oil and gas reserves and production are the primary source of cash flow and generally the highest return operations for an integrated or independent E&P company. The reserve base drives most of the key metrics and is the source of the company s greatest exposure to commodity price risk, capital re-investment, and market valuation. Reserve analysis focuses on the quality or economic value of the reserves, portfolio balance, cost structure, and on the cash flow and value of production. Reserve analysis helps pinpoint a company s sensitivity to price declines, the source of poor returns, 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 intersect with the financial statements to get a better picture of the asset and cash flow protection for debt holders and the quality and efficiency of a company s operations. Many of these measures can be derived from the annual disclosures mandated by the SEC pursuant to FAS No. 69 Disclosures about Oil and Gas Producing Activities. In addition, in areas 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 comparability. These often concern the classification and valuation of reserves as proved, probable and possible. (Please see Glossary for definitions of some terminology.) These data should be analyzed over time (three, five and ten year periods are most common) to discern trends and to smooth out single-year anomalies in reserve bookings or finding costs and the impact of one-time events. Multiyear analysis also better reflects the multi-year petroleum investment cycle and the long-term perspective needed to build reserve value. RESERVE ANALYSIS SOME QUALITATIVE ISSUES Reserve-based measures point up significant company and industry trends and provide the basis for further analysis of a company s operations. However, a number of qualitative issues need to be considered to understand a company s numbers 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 company s reserves and production, their geographic diversity or concentration and, as previously noted, some assessment of political risk. All other things equal, a large well-diversified portfolio of production, staged development and exploration prospects provides better protection 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 company s remaining historical cost incurred in finding and developing reserves, without reference to fluctuating commodity prices or the inherent uncertainty in measuring reserves. Reserve quantification and valuation is part art and part science. Management does have considerable flexibility with respect to the timing of reserve bookings and the quantity of recoverable reserves is subject to varying degrees of uncertainty. Recoverable reserves are only an estimate and therefore subjective data points that are difficult to assess from public disclosures alone. Reserves frequently change hands and buyers and sellers often have different views on recoverable volumes. In addition, companies generally are looking to show reasonable or acceptable growth in both production and reserves. A careful look at the sources of newly booked reserves from drilling, revisions, field extensions, enhanced recovery, and acquisitions, and other patterns, such as repeated downward revisions, is necessary and can be helpful in assessing how conservative or aggressive management is in financial disclosures and booking practices. Moreover, the extent to which different companies use indepen- Moody s Rating Methodology 7

8 dent reserve engineers varies significantly and can become a critical issue, particularly in evaluating independent E&P companies. The challenge is compounded in analyzing reserves for some companies in emerging markets such as the former Soviet Union, where the only reserve evaluations may be internally generated and not in compliance with SEC or other international standards. Moody s believes the use of reputable independent reserve engineers can lead to more conservative 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 reserves is 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 oil production is a global business and is readily traded by ship, natural gas opportunities are more tied to existing pipeline infrastructure and localized demand. Prolific, high quality oil or gas reserves will have higher finding and development and transportation costs, and exact a high risk premium if they are remote and limited by infrastructure or political considerations. The physical characteristics of petroleum reserves will affect finding and operating costs, revenue realizations, and upstream profits. A first look would involve the mix of oil and natural gas in the reserve and production base since pricing for the two commodities is driven by different factors. Physical properties refer to characteristics such as highvalue light sweet crude vs. lower-value heavy sour crudes, metals content, dry vs. wet natural gas, and numerous other factors. These determine a company s price realizations, which can deviate significantly from spot market indicators such 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 operating history in a country or basin, technology such as horizontal drilling, or a type of play such as heavy oil. Related indicators include a company s large ownership or production sharing interest and status as a field operator, which give it greater control over its capital spending and cash flows. Integration: For integrated companies, equity access to specific crude slates and linkages between upstream equity reserves and downstream refining and chemical configurations can have a significant impact on profitability and operating strategies. ASSET PROTECTION AND RESERVE LEVERAGE KEY METRICS Barrel of oil equivalent (BOE) Reserves: A company s 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 debt protection (as opposed to equity valuation, which focuses on upside growth potential). Proved reserves come from known reservoirs and can be produced with reasonable certainty under current pricing and technological operating assumptions. Proved reserves are subdivided into categories that reflect differences in the timing, certainty, and the capital needed to bring proved reserves into production and, therefore, the relative debt protection in the proved reserves. Proved developed reserves (PDs) are produced from existing wells. They have the greatest degree of certainty and are the primary source of operating cash flow, providing funds to maintain existing production and invest in exploration and development for new reserves. Other sub-categories 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 don t give credit to these categories, they can be germane to the economics of reserve acquisitions and major project investments that precede reserve bookings. PD reserves typically compose upwards of 75%-80% of the proved reserves of integrated companies. However, in recent years PUDs have increased as a relative share of total proved reserves, particularly among the independent E&Ps, most of which have 30% or more of their reserves booked as PUDs. While an increase in the proportion of PUDs is not necessarily problematic, PUDs require capital investment and carry higher geological risk than developed reserves and can distort various reserve and cost metrics such as RLI, reserve leverage 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 and production. Reserve Life Index (RLI): In theory, the RLI measures how many years a company can produce hydrocarbons at current production rates until reserves are depleted. RLI assumes no replacement of reserves. It is expressed in years, and can be measured on a BOE basis, for either oil or natural gas, or on a total proved or 8 Moody s Rating Methodology

9 PD basis. Most of the integrated majors have total RLIs on proved reserves in the year range, in many cases bolstered by long gas reserve lives. The independents have shorter RLIs with total RLI in the area of 10 years, but significantly shorter PD reserve lives in the 6-8 year range. A longer proved developed reserve life generally affords the producer more capital investment flexibility and should indicate better production support for debt service. In effect, it means the reserve replacement treadmill is less onerous and that a company has more flexibility to reduce capital investment and ride out a period of low prices without seriously impairing its asset base. RLI does not address reserve quality and it needs to be analyzed along with other reserve characteristics. For example, a long RLI can indicate an increasing percentage of PUDs, which effectively lengthens the reported total RLI, since total current production is measured against undeveloped reserves that are not producing. Other implications of a long RLI could be the reflection of long-lived high cost reserves with a low net present value (NPV), or in the case of some of the national oil companies such as Petroleos de Venezuela or the newly privatized Russian companies, long-lived resources whose low production levels indicate the need for significant development spending, infrastructure, or commercial market developments. When Moody s assesses a company s RLI, we focus on the absolute level of the PD reserve life and the RLI trend, particularly for the independent E&Ps. This measure considers only those reserves that are already developed (and usually producing) and thus provides a clearer indication of how long current production can be expected to last. Also, the PD reserve life eliminates the impact rising PUDs may have on the reported total RLI. We will also typically adjust RLI for acquisitions and significant new production volumes. To do this we will consider a company s exit rate of production during a given period. The assumption is that the company can produce at that exit level in future periods, giving a better indication of the true reserve life. We also factor in the volumetric half-life of wellbores coming online and the characteristics of the various basins in which a company operates to quantify the PD reserve life in a particular area. This analysis seeks to identify pockets of short-lived or high decline rate production, as well as their impact on the company s ability to defer capital spending during periods of weak commodity prices. It should be evident that this analysis becomes more critical for smaller E&Ps or companies with highly concentrated basin risk. Production Profile: An assessment of a company s current and projected production growth and where it will come from are essential to judging credit risk. Larger and more mature companies have a base load of stable cash generating fields to underpin their drilling programs and usually can project production out three to five years from current development and identified discoveries. These profiles are usually publicly disclosed, albeit in varying detail. However, many variables and assumptions are involved, and the farther out a projection extends, the less certain the ultimate outcome. The depletion profile of a producing property should be well understood to assess cash flow coverage, reserve life and reinvestment risk. For example, a company could have short-lived reservoir with a high decline rate (as is the case in the Gulf of Mexico), a longer-lived field with several years of plateau production and a long tail, or mature long-lived production from a heavy oil field with a lower present value. SEC Net Present Value of Reserves (NPV): NPV provides an alternative valuation of a company s equity and future cash flow to traditional balance sheet analysis. NPV analysis discounts all of a company s projected future cash flow from proved reserves to derive a single present value in dollars, after deducting the various future expenses related to oil and gas development and production. The measure has certain limitations: it is basically limited to SEC reporting companies and calculation methodology can vary significantly from company to company. Moreover, NPV is calculated at year-end based on then prevailing oil and gas prices, using a fixed 10% discount rate and assuming no escalation in pricing over the life of the reserves. It can thus fluctuate significantly from year to year, based not only on changes in reserve volumes, but also due to year-end price fluctuations or small changes in other assumptions. Still, NPV is valuable for company-specific analysis and peer group comparisons. Various NPV ratios can shed light on future cash flow per barrel (NPV/BOE), reserve support for debt service (NPV/Total Debt), and the integrity of balance sheet asset and equity values (NPV/Capitalized Costs). The latter constitutes a quasi ceiling test on the capitalized value of a company s petroleum reserves. Total Debt/BOE Reserves: This leverage ratio measures the amount of financial leverage carried on each barrel of proved or PD reserves and is based on the idea that petroleum reserves are a company s most important (or only) leverageable asset class. For oil companies, this measure is preferable to traditional debt/capitalization ratios, which are limited and highly variable in their accuracy and comparability due to accounting methods (Successful Efforts vs. Full Cost), the variance between book and current market values for reserves, and other factors such as large goodwill balances. We also use the Debt/PD BOE reserves measure as a more stringent measure of leverage and reserve protection. Undeveloped reserves require capital to achieve production and therefore are not leverageable or available for debt service. For the integrated oils, Debt/BOE is in Moody s Rating Methodology 9

10 the range of $1-$2 per BOE, with no debt allocated to other sectors than the upstream. For solid investment grade E&P companies, the ratio tends to be in the high $2.00 to high $3.00 per BOE range. It should be emphasized 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 within those 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) to include off-balance-sheet and other debt-like obligations. A limitation of this measure that should be noted is that for the integrated oil companies, or for independent E&Ps with other significant operations such as midstream or chemical assets, these reserve measures do not give credit to the cash generating and leveraging attributes of those businesses. For the integrateds, it is difficult to allocate a portion of the company s debt to their 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 determine the amount of leverage the non-e&p operations can support and discuss the impact of that allocation on our view of financial leverage with a company s management. These allocations are subject to change and interpretation, however, and we do not currently disclose those adjustments in our peer group calculations. Cash Flow/BOE: This measures a company s cash generation per BOE of current year production, based on SEC 10 results of oil and gas producing activities rather than the consolidated cash flow statement. The cash flow (net income + DD&A) is on an unleveraged basis, calculated after tax, but before corporate interest expense. 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 added in a given year versus that year s production. It can be refined to measure replacement from all sources or from discoveries, reserve extensions, or acquisitions. A careful look at the sources of replacement can get at the quality of a company s drilling efforts and success over time. For example, a pattern of extensions and upward revisions could evidence conservatism in reserve booking practices, while frequent downward revisions could indicate liberal booking practices, unduly optimistic assumptions, or adverse changes in the economic environment. Over the past decade, total reserve replacement for the majors has been on an improving trend, supported in large part by acquisitions. Most have showed strong replacement from all sources over both three and five year periods, including field extensions and enhanced recovery, indicating the depth of their 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 fundamental challenge of replacing large declining mature basins. Drill bit replacement for many of the stronger independents has been relatively higher, although core field declines and shrinking discoveries in core U.S. and Canadian 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 company s total reserve replacement and can be categorized as follows: revisions, extensions & discoveries, purchases, production and asset sales. Purchases, production, and asset sales are fairly self-explanatory and provide useful information. However, reserve additions due to upward or downward revisions and to extensions & discoveries may shed even more light on key attributes of the reserve base and the effectiveness of capital invested. Negative 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 can indicate reserve problems. It is important to explore the reasons behind these negative revisions and whether similar problems may arise in other areas. Price-driven revisions also need to be assessed. The standard practice is to estimate year-end reserves based on year-end commodity prices held constant (with some flexibility to adjust for existing hedge positions). Moody s looks at how sensitive a company s reserve base is to changes in commodity prices, especially if prices are unusually high at the calculation date. Similarly, it is quite common for international reserves to be subject to a production sharing agreement (PSA) or production sharing contract (PSC). These are often structured to return more barrels to the host country when oil prices are high, resulting in a negative revision for the company. These contracts also provide some type of floor or recovery mechanism when oil prices are low, resulting in a positive revision. Extensions and discoveries can also add to the underlying reserve base and may provide an indication that exploration or development strategies are progressing as planned, but again, it is important to understand the nature of the change and the underlying assumptions. 10 Moody s Rating Methodology

11 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 company s current success 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 reserve quantities or flow at rates sufficient to be commercially viable. More qualitative information is usually necessary to make an informed judgment about drilling success Finding & Development Costs (Replacement Costs) per BOE: This is a unit measure of the total cost incurred to add and develop a barrel of new reserves to the point of production. The lower a company s F&D costs, the more profitable its oil and gas activities will be in a wider range of price environments. F&D costs are subject to numerous variables, including the complexity and size of the reservoir, reserve booking practices, and timing issues such as development approvals. F&D costs are best measured over a period of years to catch the inherent lag between capital spending and booking of reserves, and to reduce distortions caused by one-time events. We look at F&D costs from all sources (acquisitions + exploration + development) and from drilling only to better judge a company s drilling success (rather than from acquisitions). Industry wide, F&D costs have been rising fairly steadily since the late 1990s, reflecting reduced exploration, lower drill bit replacement, rising service sector costs and more remote higher risk drilling areas. The largest majors have managed on an all-in basis to maintain fairly competitive F&D costs above $5/BOE on a volume weighted average basis, while most of the large E&Ps are somewhat higher in the $6.50-$7.00/BOE range, again showing a rising trend on a multi-year basis. Production (Lifting) Costs per BOE: This measures the total current cash operating cost of bringing a barrel of oil to the surface. Production costs generally include operating, gathering and processing, well maintenance, facility and equipment costs, direct administrative expenses and production taxes. They can vary greatly depending on the type of reserves being produced and the efficiency of a company s operations. Production costs are particularly important in assessing a company s cash realizations and ability to produce profitably in a given price environment. Full Cycle Costs per BOE: Total full-cycle analysis considers all the cash costs required to produce and sell a company s reserves as well as the costs (albeit historical) of finding and developing new reserves to replace those produced. It puts the total cash costs of finding, developing and producing reserves on a comparable unit cost basis and can be viewed as a reasonable proxy for a break-even price analysis. In general, lower total full-cycle costs are viewed as a credit positive because they usually result in higher profits and cash flow and provide a company with greater flexibility during periods of weak commodity prices. The full cycle cost per BOE sums the 3-year average F&D costs (all sources) per BOE with total cash costs per BOE. These cash costs include production or lifting costs, cash G&A costs (i.e. adjusted for any capitalized amounts), gross interest expense and preferred dividends. We evaluate total cash costs on an unleveraged basis before interest and preferred dividends, which excludes the impact of capital structure, and on a leveraged basis after interest and preferred dividends. Whenever possible, reported company numbers are adjusted to eliminate differences that may arise due to different accounting methods or classifications of certain costs to make analysis comparable 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 much cash a company generates in excess of its costs of replacing reserves, which would be available for further investment in growth. It is calculated by dividing a company s cash margin per BOE (production revenues less cash costs including interest expense) in a given year by its 3-year average F&D costs (all sources), to give effect to a full investment cycle. In evaluating cost structures, the ratio reflects the differences in price realizations among companies, which can be substantial. As noted earlier, the price a company receives for its oil and gas production often varies depending on location, specific product characteristics, and hedging. Production can either be sold at the well-head (i.e. before incurring transportation costs) or at certain hubs (i.e. Henry Hub or AECO). Geographic location may also impact realized prices, as international production is often subject to some type of PSC/PSA or other pricing mechanism. While this ratio factors in differences in price realizations, it is also clearly affected by commodity price levels. Therefore, this ratio can be quite meaningful when analyzed through commodity price cycles. In general, a recycle ratio that remains above 1.0x during periods of weak commodity prices is viewed positively. We have attached a sample chart (using EOG Resources) that provides an overview of the reserve and production statistics, operating and cash flow numbers, and full cycle cost structure analysis for our analysis of independent E&P companies. Moody s Rating Methodology 11

12 Refining and Marketing 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 company s financial performance from quarter to quarter. Periodic shutdowns for maintenance or turnarounds can also hurt throughput and capacity utilization. Refining margins are affected by macro factors outside the company s control such as supply and demand relationships and feedstock costs. To analyze a refiner we look at its crude slate and feedstock access, system configuration and complexity, cost structure and product yield, as well as its location, size, competitive market position, and other factors. In marketing, we look at the linkage between a company s refineries, distribution channels and retail outlets, its retail market share, whether its wholesale markets are product long or short, and its marketing strategies. Refinery Schematic Feed Stock Fractionation Upgrading/Processing Products Fuel Gas Liquified Petroleum Gas Lighter Light Gasoline Chemical Feedstocks Naphtha Reformer Blending Motor Gasoline Kerosene Jet Fuel Heated Crude Oil Diesel Diesel Fuel Heating Oil Light Gas Oil Hydro Cracker Heavy Gas Oil Fluid Catalytic Cracker Alkylation Plant Aviation Gasoline Residuum Coker Petroleum Coke Asphalt Fuel Oils Distillation Column Lube Oil Hydro Cracker Lubrication Oils Heavier KEY QUALITATIVE ISSUES Geographic Diversification: In the 1990s, many refiner/marketers pursued a strategy of geographic regionalization 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 remained more regionally focused, whereas others such as Valero and Tesoro have become more geographically diversified via acquisitions. A geographically diverse spread of refining and marketing assets can have a positive port- 12 Moody s Rating Methodology

13 folio benefit for refiner credit ratings. Exposure to seasonality, different margin characteristics, unplanned refinery 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 refinery can benefit from economies of scale to lower unit costs and is more likely to be the efficient survivor than a 50,000 bpd unit, particularly under the burden of non-productive environmental costs. The most-used measure of refining capacity is barrels per day of crude distillation capacity, which measures first stage treatment of crude inputs. A refinery may have numerous other upgrading units that run distilled crude fractions and are more relevant to determining its product slate and profitability. Refinery Configuration and Complexity: A refinery s crude diet will depend on its configuration and complexity, or the number of different operations it performs to yield higher value products. (See Refinery Schematic Chart.) A simple crude distillation refinery generally needs more expensive light crudes (30-34 degree 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 upgrade the carbon molecule. These processes enable a refinery to run lower-cost heavy sour crudes and still produce a 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 conversion refineries) typically produce 70-85% gasoline and jet fuel. Refinery Reliability: Plant reliability has a very major impact on refining costs and profitability, and industry accidents and downtime tend to increase during periods of high utilization and cost cutting. Reliability is a function of equipment age, complexity, company maintenance and safety policies, and ongoing capital investment. Indicators of reliability and operating expertise include utilization rates at the plant level, the frequency of unscheduled turnarounds and major or minor mishaps, and management s track record on restoring operations after interruptions and accidents. Crude Slate: Crude feedstocks accounting for more than 80% of a refiner s barrel of product cost. A refinery s optimal crude slate is largely determined by its complexity and location. In assessing a refinery s cost structure and competitive position, we look at its typical crude diet, light or heavy (gravity), sweet or sour (sulfur content) and the availability of supplies. A consistent and predictable crude slate enhances operating efficiency 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. refiners have invested in cracking and coking capacity based on a trend in heavier crude supplies and a longer term expectation of widening light/heavy crude differentials. Light/heavy differentials change frequently based on the relative supplies of crude on the market. Inventory Management: Management of crude and product inventories has a direct effect on financial performance. A refiner that can minimize the time lag between crude pricing, delivery, processing and product delivery can reduce working capital needs and exposure to inventory losses and adverse product price movements. This problem can be most acute in a declining crude price environment, when a refiner has purchased crude and built inventories at higher prices and can experience from days lag between crude purchase and product delivery to the market. Logistics and Location: Product supply and distribution channels have a major impact on refiner s cost structure, profitability and competitive advantages. Supply and distribution configurations are typically complex, comprising pipelines, ships/barges, trains, trucks, and crude and product storage terminals. The refiner s goal is to minimize transportation costs, ensure safety and dependability, and access the most attractive markets. Branded retail and branded wholesale markets typically offer higher margins than unbranded wholesale and spot markets. Refinery location (land-locked, on a river, near ports) not only affects market access, but also affects transportation costs, access to crude supplies, and energy costs. Proprietary pipelines or access to third party capacity can be particularly important to refiners in regions with excess supplies seeking higherreturn markets. Certain geographic markets or niche players can also have differential margin advantages. For example, 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 and product imports. Downstream Integration: Refiners invest in service stations and linked convenience stores to capture maximum value-added. Retail operations can offset volatile wholesale product margins, since gasoline margins frequently (but not always) increase when wholesale margins are under pressure. Retail integration is particularly beneficial 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 Moody s Rating Methodology 13

14 key locations. Convenience stores, likewise, attract customers and increase gasoline sales, but they also provide higher-margin revenue diversification. Convenience items carry a high margin, averaging cents per sales unit, versus typical 2 to 3 cent margins on a gallon of gasoline. For the same reasons, marketers are also linking up with fast food chains such as McDonald s. Many refiners also produce feedstocks that are strategically linked to downstream petrochemical operations and contribute to utilization and stronger margins. Retail Configuration: Different paths to branded retail marketing require varying degrees of company involvement and capital commitment. Real estate is typically one of the highest cost components in gasoline marketing and can tie up large amounts of capital. Thus, ownership and operation of a large number of stations do not necessarily lead to higher profitability. Company-controlled stations generally provide maximum financial and operating control, but also entail higher SG&A and capital costs than other distribution channels. In fact, direct company-owned and operated service stations are less prevalent than more wholesale oriented company-owned/dealer operated stations and branded jobber networks, which provide brand outlets but are much less capital and real estate intensive for the refiner/marketer. QUANTITATIVE MEASURES Standard reporting of refinery earnings and operating data make it possible to construct a reasonable picture of performance and output for most refiner/marketers, but a real understanding of unit costs, performance and profitability at the plant level is often hard to derive from reported numbers and is subject to comparability problems. We look at a number of different measures, some of the most important of which are published as the key credit statistics that accompany our quarterly opinion pages on integrated oils and independent refiner/marketers. Return and Coverage Measures: Segment pre-tax and net return on capital employed (ROCE) are the measures most widely used by the companies themselves to assess performance and make comparisons with their peer group. Among the key measures we look at are EBIT/Average Capitalization as a measure of return on debt and equity, EBIT/Operating Margin to measure the competitiveness of cost structures in a highly volatile margin sector, and standard fixed charge coverage ratios, which likewise reflect refining margin volatility. Operating segment return on assets is also an important measure but can be difficult to compare because of the different age profiles of many of the asset bases in the sector. However, non-recurring items such as write-downs and gains can affect reported capital returns and must be taken into consideration. R&M cyclicality, excess capacity and surplus supplies resulted in very poor capital returns in the past decade, in the range of 4-6%, which prompted the widespread restructuring and joint-venture efforts that have taken place. Financial Leverage: While Debt/Capitalization is often cited in financial leverage analysis, this measure for refiner/marketers can be somewhat distorted due to the mature and depreciated refining assets in the portfolio, acquisition and divestment activities, and the impact of goodwill and merger accounting. We typically focus more on Gross Cash Flow/Total Debt and Retained Cash Flow/Total Debt as measures of cash generating strength (see financial discussion below). We have also begun publishing a measure for the independent refiner/marketers, Debt per Complexity Barrel of refining capacity. This asset leverage ratio measures a company s debt burden relative to its Nelson complexity barrels, an industry classification that compares asset classes across different refiners, measuring the quality of the refineries and their future cash generating potential. In effect, it measures the amount of debt per barrel of equalized refining capacity. In theory a more complex refinery will be able to bear more leverage based on the yield of more profitable higher value products it produces. Refinery Utilization: Refinery utilization (barrels of crude input as a percentage of rated capacity) is generally viewed as a good indicator of operating efficiency since high utilization reduces unit costs and increases product sales volumes. While this can be true for the individual refinery or company, high utilization has not benefited the industry in aggregate or resulted in increased profits. In addition, utilization is usually measured on primary distillation capacity (raw crude inputs), which will not necessarily enhance profits if, for example, downstream units are out of commission and the refinery is producing a sub-optimal product stream (e.g. too much middle distillate or residual in a gasoline market). Capacity creep (cheap incremental capacity added during routine turnarounds or environmental projects) has increased sustainable processing capacity at many refineries, resulting in under-reported nameplate capacity and extremely high industry utilization in the range of 90-95%. 14 Moody s Rating Methodology

15 Crude Self-Sufficiency: For integrated companies, crude self-sufficiency measures the degree to which a refiner can obtain crude from internal upstream sources, (upstream crude produced as a percentage of downstream crude volume requirements). A higher degree of self-sufficiency would generally indicate more value added and enhanced profitability. While a high degree of crude self sufficiency can be viewed as a positive, it has become less crucial in light of plentiful crude supplies, sophisticated trading capabilities and product swap arrangements. Refinery Margin per Barrel of Output: Companies often do not publicize unit refining margins and cash operating costs because of competitive concerns. When they do, the methods used to calculate refining and retail 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 appropriate industry benchmark such as the crack spread or the heavy crack spread. Product Slate: Product slate is the mix of a refinery s end products such as gasoline, jet fuel, middle distillates (diesel) and heavy ends, usually broken down on a percentage basis. Generally, the higher a refinery s yield of gasoline and light ends, which command a premium, the more profitable it should be. A highly complex refinery can produce 75-85% light products. However, margins are affected by industry inventory levels and demand. 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 company s share of product volumes and service stations can indicate market clout and the ability to move product, but does not necessarily correlate with profitability. Market share can be measured within a company s own market area or in the context of a larger (e.g. national) scale. A major retailer such as Shell or BP can have a 20% share in selected local markets in the U.S. or national markets in Europe or Asia, and will compete head on with large regional independents, hypermarkets, and other participants for major stakes in a national market. Refined Product Integration: This ratio measures a refiner s own product self sufficiency, or output as a percentage of product sales (refined product output/total sales volumes). In theory, the more internal production, 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 is lighter and they bear high transportation and servicing costs. Industry restructuring has focused on eliminating small volume rural or urban stations that have high costs and low volumes. Financial Analysis Key Measures and Ratios CASH FLOW PROTECTION Cash flow from operations is the most important measure of a company s real debt protection capabilities. Our primary focus in cash flow analysis is the adequacy of cash flow support for debt protection, funding of capital spending and dividends, and generation of free cash flow. Our goal is to try to assess the downside risks to cash flow and kkto derive 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 dividends from gross cash flow, and free or discretionary cash flow. These measures are all adjusted for non-recurring items such as gains or losses on asset sales. It should also be noted that debt includes more than just the on balance sheet long-term and short-term debt obligations. As is discussed later, the debt number we use is adjusted to reflect a company s true financial leverage, incorporating, for example, hybrid instruments and preferred stock, as well as offbalance-sheet obligations such as operating leases, accounts receivable financings, unfunded pension liabilities, and guarantees. Retained cash flow analysis treats dividends as a quasi-fixed charge, based on the view companies generally will only cut dividends in dire circumstances. Free cash flow is the cash flow available for debt reduction and discretionary uses such as opportunistic growth projects or share repurchases after the funding of dividends and base level capital 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 off all its debt from internal cash flow. RCF/Total Debt: a more stringent and realistic starting point for cash flow analysis, since dividends for most investment grade companies are a form of fixed charge that are rarely cut except in dire financial circumstances. Moody s Rating Methodology 15

16 Free Cash Flow/Total Debt: residual cash flow protection for debt service after funding of dividends and maintenance capital. GCF/Capex: a measure of a company s 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, environmental clean-up or prevention programs, and sometimes key capital investments necessary to maintain or improve a company s competitive position. Since the industry s chief challenge is asset depletion, maintenance capital includes core spending necessary to replace reserves. (In reality, stronger companies with deeper reserve bases can cut these investments during periods of stress without permanent impairment.) In the petroleum industry, maintenance spending should also include future contractual spending commitments, which are prevalent via partnership arrangements and long-term supply relationships. A useful, albeit simplistic, proxy for maintenance capital needed to replace 100% of production is to multiply a company s F&D costs (e.g. three year average) by annualized BOE production. For example, 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 internally fund capital spending. Fair amounts of non-core asset sales also routinely supplement operating cash flow for these mature 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 can contribute to rising financial leverage. Cash flow for independent E&P companies and refiner/marketers tends to be more volatile. E&P cash flows are exposed to fluctuating commodity prices and large investments to replace reserves, and the impact of capital curtailments can be more severe for an independent than for an integrated major. The refining and marketing industry benefits from cyclical periods of free cash generation and can more readily curtail discretionary growth projects without permanent impairment. Nevertheless, volatile margins and mandated capital can hurt earnings and absorb free cash flow, as happened in the mid-1990s when the industry made major investments for clean fuels and other environmental mandates. We believe price risk and high capital requirements make high dividend payouts and share repurchase programs unadvisable for independent E&P companies, and generally negative credit events both for debt protection and for future growth. CAPITAL SPENDING ANALYSIS Capital spending analysis is helpful in understanding a company s operating strategies, growth plans, and areas of under-investment and de-capitalization. More than two-thirds of the petroleum industry s capital spending is invested in the upstream sector. Refining, marketing and chemicals are also capital intensive and subject to cyclical spending patterns. 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 future reserve replacement and long-term production growth. Maintenance capital needed to replace reserves and maintain plant and equipment for safety and efficiency. In the downstream, maintenance of plant and environmental outlays are generally non-discretionary and should be factored into base capital spending. Major long-term projects: what levels of capital are committed and possibly beyond the company s control as to timing? Are such projects vulnerable to political disruption or sensitive to changes in the economic/pricing environment and changing market conditions? Changing environmental or other regulatory events that may result in increased mandatory investment. FINANCIAL RETURNS AND QUALITY OF EARNINGS While cash flow is of primary importance for debt holder protection, financial returns are key to a company s ability to attract future capital for investment and thus to maintain or improve its long-term financial health. We analyze the contributions of a company s 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 company s 16 Moody s Rating Methodology

17 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 industry pressure points and trends. Return on capital employed (ROCE) is one of the industry s most widely used return benchmarks, both for operating divisions and the consolidated company. We also look at pre-tax return on capital as an indicator of operating return on debt and equity. Other important return measures include operating and net return on sales (ROS), return on assets (ROA), and return on equity (ROE). ROS and ROA are useful for high revenue, capital intensive portions of the operations such as refining and marketing. Most of the majors view a 12-15% ROCE as an acceptable capital return on a mid-cycle basis, recognizing that they can be higher or lower depending on the cycle. Despite rigorous streamlining and cost reductions, this target has proved difficult to achieve on a sustainable basis due to depressed upstream pricing and the capital tied up in downstream operations. The R&M sector typically has returned no more than a 5%-6% return on capital compared to significantly higher upstream returns, which explains the industry s ongoing 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 and the 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 company s reported exploration expense and earnings and the capitalized value of its oil and gas operations, mainly due to differences 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 against earnings when incurred. The full cost method capitalizes dry holes and amortizes them against all future production. In effect, it treats dry holes as part of the full cycle of costs needed to bring successful wells onstream. Other costs incurred also are capitalized, including interest costs and certain components of SG&A that would be expensed under Successful Efforts. Successful efforts can lead to more volatile earnings. Full cost tends to overstate the balance sheet valuation of reserves and equity as reported earnings build up. The two methods should be cash flow neutral over time, since a more steady earnings profile under full cost tends to be offset by higher DD&A on the cash flow statement. From a credit perspective, successful efforts is more conservative, 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 independents use 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 able to withstand volatile earnings gyrations. Inventory Accounting: Last-in-First-out (LIFO) inventory accounting is used by virtually all the larger integrated and independent refining companies. In LIFO accounting, a company books its crude inventory purchases using the most recent crude price. During periods of crude price volatility, the time lag between feedstock 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 purchasing and carrying crude oil are the same. LIFO also means that inventory carrying values can be undervalued on the balance sheet (the LIFO Cushion), particularly for long-established companies that carry many layers of cheap oil on their balance sheet. Costing through or drawing down these older low priced layers can 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 levied on the industry. Statutory tax rates may differ dramatically from cash taxes paid depending on spending levels 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 can mask a company s underlying operating performance. Major sources of such charges, which may or may not have a cash impact, include reserve sales and ceiling test writedowns; the restructuring or sale of under-performing refining and chemical assets; personnel reductions and associated severance programs; and exits from non-core businesses such as coal and metals. We look at the cash impact of the charges on reported earnings and cash flow. Impairment/Ceiling Test Writedowns: For companies following successful efforts accounting, FAS 144 prescribes procedures for assessing impairments in the value of long-lived assets. For the petroleum industry, the rule s primary impact is on reserves, which can be written down during periods of price volatility. The impairment 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 Moody s Rating Methodology 17

18 cash flows are less than book value, the assets are impaired. Alternatively, if the undiscounted future cash flows exceed the book value of the asset, then no impairment is recognized, even if the fair value of the assets is less than the book value. Once an asset (a field) is determined to be impaired, a charge is taken against income to writedown the assets to their fair value, reducing reported earnings and book equity. For companies following full cost accounting, the rules for assessing reserve impairment are included in SEC Regulation S-X, Rule 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% discount rate. This ceiling amount is compared to the book value of the full cost pool and if the ceiling is lower, 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 overvalued assets. Overtime they also can mask bad investment decisions (e.g. inflated acquisitions) and provide a quick fix for poor capital returns. The writedowns can also be somewhat punitive on economic values. Once reserves are written down, they cannot be written back up even if the price decline proves to be temporary and the reserves will be producing for many years. In general, these non-cash writedowns do not affect credit ratings, although they can be indicators of potentially serious financial stress or can trigger liquidity problems, particularly for smaller capitalization companies that have borrowing bases in their bank loan agreements. FINANCIAL LEVERAGE AND BALANCE SHEET ANALYSIS As noted, traditional leverage ratios such as Total Debt/Equity and Total Debt/Total Capitalization are merely starting points in assessing a petroleum company s financial leverage. These ratios in isolation can be unsatisfactory leverage indicators since the capitalized value of property, plant and equipment and book equity values do not reflect current pricing or the true underlying value of oil and gas reserves in the ground. Moreover, in the downstream, the depreciated value of refining and petrochemical plants often does not reflect replacement value. To get a better picture of leverage, we look at a company s cash flow protection relative to debt, focusing on current operating cash flows and on the discounted SEC NPV of reserves. Segment operating results and capital returns can also point up weaknesses in asset and equity values, which are adjusted accordingly. Large integrated companies with diversified cash flows can bear more debt than smaller independent E&Ps or refiners. However, volatile commodity prices, significant capital requirements and the need to maintain financial flexibility for late breaking business opportunities 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 of debt holder protection. However, we do look at a company s market valuation as a check relative to its book financial leverage, as well as a significant indicator of market pressures that could motivate management to use stock as currency in 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 are incorporated into our adjusted total debt calculations. These liabilities are becoming more significant in the industry as companies enter into project financings and other forms of joint-ventures and alliances that incur their own direct debt obligations. 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 parent s debt capacity, 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 finance service station networks, drilling rigs, and other assets. We typically treat these leases as a use of debt capacity since retailing 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 sheet debt to determine adjusted leverage. Other liabilities include throughput and deficiency obligations on pipeline subsidiary debt, where the parent must supply a pro-rata share of throughput or cash payments sufficient to generate pipeline revenues for debt service. Line item treatment of unconsolidated equity investments (including joint ventures and project financings) can often mask large subsidiary financial obligations that may or may not make some implied call on parent company support. Certain forms of performance, completion and financial guarantees are disclosed in footnotes but are not reflected on the balance sheet. Large project financings, structured to be legally non-recourse to their sponsors, can have substantial pre-completion supports such as unlimited completion guarantees or strategic significance that implies 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. 18 Moody s Rating Methodology

19 LEGAL STRUCTURE AND COVENANTS Moody s long-term debt and preferred stock ratings are applied to specific securities issues, based on our fundamental view of a company s senior unsecured credit quality and reflecting the legal position of a specific security and creditor within the company s capital structure. In rating securities, we place particular emphasis on covenants that affect cash flow movement between an issuing entity and its various affiliates (dividend restrictions, limitations on subsidiary debt issuance) and on the investor s clear access to that cash flow. Also of considerable importance are restrictions on security interests and an issuing entity s 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 their public debt that provide wide flexibility and few restrictions that protect bondholders (perhaps debt incurrence, minimum tangible net worth, etc.) Low investment grade and high yield companies with more limited financial flexibility tend to have more classes of securities with a wider spread of ratings, reflecting the increased risk of default and differing classes of creditors. Reserve-based lending facilities and security interests in reserves or other assets also become more significant in assessing debt holder protection. In reserve based lending, access to bank funds is based on commodity pricing and other assumptions that are periodically reviewed and determined by lenders. Thus, changes in commodity prices can adversely affect a company s liquidity and ability to fund its operations. Regarding security, bank lenders often have a senior position and secured interest in the company s 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 LIQUIDITY Moody s analysis of financial flexibility focuses on the company s ability to generate cash under stress scenarios and maintain sufficient liquidity to meet maturing debt obligations in a timely manner. We do not generally rely on standard liquidity ratios since they are static in nature and often have limited value. To take an extreme case, a company might have sufficient cash available to meet near-term maturing obligations but could still default if its Board projected a serious cash flow deficit in six months and decided to declare bankruptcy to conserve resources and pressure creditors to re-negotiate their agreements. In assessing liquidity we look at the company s liability structure: are short near-term and long-term maturities well placed and appropriate to the company s cash flow profile? Does the company face large debt maturities in a short time frame? The petroleum business and oil pricing historically have been viewed to have something of a natural hedge 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 sheets somewhere in the 30-50% fixed range. We also look at whether a company s cash or marketable securities are readily converted into cash. We evaluate the quality, maturity and liquidity of the securities, the company s normal operating cash position, and possible currency exchange losses or tax consequences that could be impediments to quickly converting securities to cash. Another key liquidity component is the reliability of an issuer s borrowing power under stress scenarios: the strength of contractual lending commitments (committed bank agreements vs. uncompensated credit lines), the quality of the lending institutions, and the history and strength of a company s banking relationships. Alternate liquidity is critical in rating commercial paper because of the instrument s short maturity profile and the inability of even highly rated companies to repay maturing commercial paper on short notice from internally generated cash. Our alternative liquidity evaluation is based on a one-year time horizon and assumes loss of access to the commercial paper market in a stressful but plausible scenario of market turbulence and general illiquidity. Quality of Management The quality of a company s management is one the most important and difficult to quantify factors in the credit rating process. Our assessment of management s abilities and risk appetite can often be the deciding factor in a rating. Management controls all the internal elements central to a company s credit quality, including most importantly, the company s risk appetite, controls, leverage targets, and philosophy on use of financial leverage and shareholder rewards. Management must also react to and deal with the larger industry environment outside its control. We evaluate management s track record, its strategies for future growth and core operations, and its financial policies and control systems. The company s strategic direction should derive from management s views of the larger business environment and where it sees the company s strengths and weaknesses. Implicit in this is management s appetite for business/operating risk and financial risk. We have attached as an addendum a brief summary of the more important issues we examine and questions we ask in evaluating management. Moody s Rating Methodology 19

20 Event Risk A final consideration is the possibility that a special event could cause a sudden and sharp decline in an issuer s fundamental creditworthiness. Special events have an unavoidable element of surprise because their precise timing, nature, and impact on a company s creditors cannot be predicted in advance by the tools of fundamental credit analysis. Typical special events are mergers and acquisitions, capital restructuring programs such as large share repurchases and, at the extreme, leveraged buy-outs. For commodity-based industries, prolonged periods of price weakness often force industry consolidation and increase the probability of event risk. Low upstream pricing and weak downstream returns were the impetus for much of the merger activity in the late 1990s, which extended to the integrateds, refiner/marketers and independent E&Ps. Event risk tends to affect a company s credit fundamentals most significantly when it involves a major change in company management or a dramatic increase in debt leverage. Most recent mergers have not resulted in downgrades largely because of the potential cost savings, enhanced asset bases and market position, and generally conservative equity financing involved. Large debt-financed reserve acquisitions frequently result in downgrades since high fixed charges and reduced financial flexibility are incompatible with volatile commodity prices and cash flows. Over the past decade, 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. When litigation is involved, we try to determine possible outcomes, looking at the company s liquidity and financial reserves, as well as its ability to sustain large cash outflows and maintain financial flexibility. To a certain extent, share repurchases can be viewed as a predictable event, in which case we try to look at the market forces motivating the repurchases and management s own appetite for shareholder rewards. Conclusion Moody s credit ratings for petroleum companies synthesize a company s financial and operating profile and our expectation for future performance and debt protection measures in light of specific company and industry risks. Our analysis starts with company cash flow and balance sheet analysis historical and projected and is expanded to include significant underlying petroleum reserve and production valuations and trends derived outside the financial statements. 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 entail significant geological and other risks, with large ongoing investment to offset depletion. In addition, a company s nominal balance sheet values do not reflect the underlying value of reserves in the ground, or their future cash flow and profit 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 Moody s 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 this report and that more recent reports may be available. All research may not be available to all clients. 20 Moody s Rating Methodology