Key Credit Factors: Criteria For Rating The Global Midstream Energy Industry
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April 18, 2012
Criteria | Corporates | Industrials:
Key Credit Factors: Criteria For
Rating The Global Midstream
Energy Industry
Primary Credit Analyst:
David Lundberg, CFA, New York (1) 212-438-7551; david_lundberg@standardandpoors.com
Secondary Contacts:
Nicole Martin, Toronto (1) 416-507-2560; nicole_martin@standardandpoors.com
Elena Anankina, CFA, Moscow (7) 495-783-4130; elena_anankina@standardandpoors.com
Criteria Officer:
Mark Puccia, New York (1) 212-438-7233; mark_puccia@standardandpoors.com
Table Of Contents
SCOPE OF THE CRITERIA
SUMMARY OF CRITERIA
IMPACT ON OUTSTANDING RATINGS
EFFECTIVE DATE AND TRANSITION
METHODOLOGY
Summary Of Key Credit Factors
Part I--Business Risk Analysis
Part II--Financial Risk Analysis
Related Research
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958902 | 301674531Criteria | Corporates | Industrials:
Key Credit Factors: Criteria For Rating The
Global Midstream Energy Industry
(Editor's Note: This article supercedes and partly amends "Rating Criteria For U.S. Midstream Energy
Companies," published Dec. 18, 2008.)
1. Standard & Poor's Ratings Services is refining its criteria for the global midstream energy industry. We are
publishing this article to help market participants better understand the key credit factors in this industry. This
article relates to "Principles Of Credit Ratings," published Feb. 16, 2011, on RatingsDirect
SCOPE OF THE CRITERIA
2. These criteria apply globally to ratings on issuers in the midstream energy industry and to ratings on diversified
energy companies with material midstream operations, except for rate-based midstream assets that regulated utilities
own. In these cases, our criteria on regulated utilities apply.
SUMMARY OF CRITERIA
3. These criteria specify the key business and financial risk factors that comprise our credit analysis of issuers in the
midstream energy industry.
4. We divide the criteria into three key credit factor categories. These are:
• Category 1 factors are, in our view, the most relevant; typically, they meaningfully affect the rating outcome, and
in many instances are critical to our rating conclusions.
• We view Category 2 factors as being of lesser relevance, but they may in some instances still prove critical.
• Category 3 factors may be individually meaningful in a few instances, but ordinarily they just shape the
company's overall profile in conjunction with the other factors.
IMPACT ON OUTSTANDING RATINGS
5. We do not expect implementation of these criteria to cause rating changes.
EFFECTIVE DATE AND TRANSITION
6. These criteria are effective immediately.
METHODOLOGY
7. Standard & Poor's divides its analytic framework for industrial companies in all sectors, including the midstream
energy industry, into two major segments. The first is fundamental business risk analysis. This step forms the basis
and provides the industry and business contexts for the second segment of the analysis, a financial risk analysis of
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the company.
Summary Of Key Credit Factors
8. In addition to the three categories of key credit factors listed above, we also discuss industry risk factors pertinent to
our ratings process in the Industry Risk section of this report. We believe the midstream energy industry involves
lower credit risk when compared with other industries and sectors as explained in the Industry Risk And
Characteristics section below (see paragraphs 13 though 31 and chart 1.)
9. The following are the Key Credit Factors we evaluate for issuers in the midstream energy industry.
10. Category 1 factors:
• Resiliency of commodity-related volume flows,
• Contract profile, specifically the type and length of contracts and the creditworthiness of counterparties,
• Degree of commodity price exposure,
• Scale and geographic diversity of operations,
• Financial policy,
• Cash flow adequacy,
• Capital structure and leverage, and
• Liquidity/short-term credit factors.
11. Category 2 factors:
• Regulatory framework under which a midstream energy company operates, and
• Scalability of growth-related capital spending programs and characteristics of maintenance capital spending.
12. Category 3 factors:
• Diversity/integration with other business lines, and
• Cost profile of operating assets.
Part I--Business Risk Analysis
13. We subdivide business risk into four categories: country and macroeconomic risk, industry risk, a company's
competitive position (including management), and profitability/peer comparisons. We evaluate each category, and
then determine a score for overall business risks: Excellent, Strong, Satisfactory, Fair, Weak, or Vulnerable.
Country risk and macroeconomic factors (economic, political, and social environments)
14. Country risk plays a critical role in ratings on companies in a given country, and this is particularly true in the case
of exploration and production (E&P) companies. Country-related risk factors can substantially affect--directly and
indirectly--a company's creditworthiness. The risk of doing business in a particular country differs from sovereign
credit risk--the risk of the sovereign defaulting on its commercial debt obligations. We therefore look beyond the
sovereign rating to evaluate the country-specific risk that may affect an entity's creditworthiness, where such country
risks include economic, political, legal, and regulatory risk, and infrastructure or labor market constraints.
Regarding the midstream energy sector specifically, a country's natural resource endowment, its geopolitical status,
seasonality of energy consumption, and the regulatory framework can meaningfully affect credit quality.
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Industry risk and characteristics
15. In establishing a view of the degree of credit risk in a given industry, we find it useful to consider how its profile
compares with those of other industries. Risk categories are broadly similar across industries, but the effect of these
factors can vary markedly among industries. (See chart 1; the key industry factors are scored: high risk [H, red],
medium/high risk [M/H, red], medium risk [M, orange], low/medium risk [L/M], green), and low risk [(L, green].)
Chart 1
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16. Broadly speaking, the lower the industry risk, the higher the potential rating on companies in that sector. Industry
risk identifies the range of business risk profile scores we generally expect to assign an industry. We have found that
those sectors with lower industry risk will tend to have higher business risk profile scores than those sectors with
higher industry risk. However, a high industry risk profile does not automatically limit our rating on a company.
Companies can differentiate themselves regarding business risk, and may be able to mitigate certain business risks
with cautious financial strategies.
17. Industry risk analysis sets the stage for company-specific analysis. Once key country risk and industry risk
considerations are identified, our credit analysis process proceeds to a second phase--company-specific analysis. If,
for example, we view technology as a critical competitive factor, our analysis typically places greater weight on a
company's research and development capabilities. If the industry produces a commodity, production cost is of major
importance. The goal of our approach is to develop a robust understanding of the company's external operating
environment when evaluating its overall business position. Industry analysis focuses on industry prospects, and
identifying the competitive factors, risks, and challenges affecting participants in that industry. The degree of
business risk facing a company almost always depends on the dynamics of the industry in which it participates.
Different industries pose different risks and opportunities for the companies that operate in their sectors.
18. Our evaluation of a company's competitive position identifies those entities that we believe are best positioned to
take advantage of these key industry drivers--or to mitigate associated risks more effectively. They should show a
competitive advantage, and a stronger business risk profile compared with those companies lacking a strong
competitive value proposition, or that are more vulnerable to sector risks. When combined, our view of a company's
competitive position is shaped by the industry risk of the sector(s) in which it operates, thus establishing our overall
view of the enterprise's business risk profile.
19. The following are major industry risks in the midstream energy industry:
• Commodity price volatility,
• General economic conditions.
• Changes in volume flows, either due to regional supply or demand changes,
• Competition and the risk of overcapacity, and
• Construction risk.
20. The midstream energy sector transports, processes, stores, and markets commodities such as crude oil, refined
products (e.g., gasoline and diesel), natural gas, and natural gas liquids (NGL). The sector connects oil and gas E&P
(or, "upstream") activities with oil refiners and retail marketers (collectively referred to as the "downstream"
sector), utilities, and industrial users (see chart 2). In addition, some midstream operators handle other commodities
such as ethanol, ammonia, asphalt, and coal.
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Chart 2
21. In most countries, oil and gas companies operate as integrated companies, and there are few, if any, independent
midstream companies. In such cases, these criteria apply to the midstream segment of these companies' operations,
assuming sufficient segment-level disclosure exists. In the U.S. and Canada, the independent midstream energy sector
has grown significantly over the past 20 years and there are now a large number of companies. In the U.S., many are
organized as master limited partnerships (MLP). In Canada, many initially were organized as income trusts, but
converted to corporations following changes to income tax laws.
22. As a whole, the midstream energy sector has below-average industry risk due to its relative cash flow stability. In
contrast to E&P or oil refining, midstream energy tends to exhibit only moderate cyclicality and has limited direct
commodity price risk.
23. Midstream energy encompasses several subsectors. While overall industry risk is below average, it can vary
materially depending on the subsector (see chart 3). The largest subsectors are:
• Long-haul pipelines: This segment usually exhibits the greatest cash flow stability due to limited competition
among main routes, long-term contracts, little historical volatility in throughput volumes, and low commodity
price exposure.
• Storage and terminaling: Similar to long-haul pipelines, these assets generate stable cash flows from fee-based,
albeit shorter-term, contracts. There is greater risk of oversupply in a given market, which can lead to lower
revenues when contracts come up for renewal.
• Gathering lines and intrastate pipelines: These assets have limited direct commodity price exposure, but volumes
can be more variable. Volumes, in turn, depend on commodity prices and the geological characteristics of the
basins they serve.
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• Natural gas processing and NGL fractionation: Natural gas processing and NGL fractionation assets often have
some direct exposure to volatile NGL prices, although contract structure can mitigate this risk.
• Propane, crude, and heating oil marketing: While there is limited direct price exposure, these sectors are intensely
competitive and have inherently low profitability.
Chart 3
24. The chart shows, in general, the business risk profiles associated with each subsector. There can be exceptions, as
this article outlines.
Commodity price volatility
25. Many midstream segments are sensitive to commodity prices, such those for as crude oil, natural gas, and NGLs,
albeit in different ways:
• Natural gas processing and NGL fractionation often have some direct exposure to commodity prices. In many
cases, operators receive a percentage of the liquids that the processing plant produces.
• The relative price of liquids versus natural gas can affect cash flows. Certain processing contracts known as
"keep–whole" expose midstream operators to the price spread between liquids and natural gas. Specifically,
profits increase when liquids become expensive relative to natural gas, but decrease when they become cheaper.
• Gathering operations are not directly exposed to commodity prices, but are usually sensitive to the volume of
hydrocarbons that flow through their systems. Lower commodity prices can lead to reduced drilling activity,
which can lead to lower volume flows.
• The slope of the futures curve of traded commodities, rather than the absolute price, can affect the demand for
storage facilities more. In contango markets (i.e., when the futures curve is upward sloping), demand tends to be
greater. When the time spread (futures price minus the spot price) exceeds storage costs, customers can generate
profits by leasing storage space. Conversely, in flat or backwardated markets (i.e., when the futures curve is
downward sloping), demand for storage tends to be less. Seasonal factors also affect demand, where consumption
levels differ from production.
• Volatility in and of itself can drive demand for midstream assets. Wholesale traders and marketers seek to
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generate profits when differences in regional prices (or, "basis differentials") and time spreads become volatile.
Such environments create arbitrage or relatively low-risk trading opportunities, and marketing and trading firms
will lease capacity on pipelines and storage terminals to execute their trading strategies. In less volatile markets,
these firms will see few profitable trading opportunities and will generally be less willing to lease infrastructure
capacity, which tends to drive down utilization and rates on some systems. Changing commodity prices also
affect retail propane and heating oil distributors. They often struggle to pass along higher costs to customers
when prices are rising, but can see short-term windfalls when prices decline.
26. Contract structure can significantly mitigate the commodity price risks outlined above. For example, if a storage
terminal has fully contracted all of its capacity for the next 10 years at a fixed fee, commodity price movements will
not affect cash flows in the interim period.
General economic conditions
27. Changing macroeconomic conditions often directly affect commodity prices, and could cause us to change our view
on such prices. In addition, they influence throughput levels.
• Refined products: Demand in this area has been historically highly correlated with GDP, but certain market
conditions can cause the relationship to break down. For example, when crude oil prices spiked sharply in 2008
to nearly $150 per barrel, gasoline demand fell by 10% in many U.S. markets, while demand for jet fuel fell even
more. During this time, GDP fell only modestly.
• Natural gas demand: Natural gas demand mainly stems from residential heating needs, gas-fired power plants,
and industrial plants (such as petrochemicals, agricultural, and steel). Weather, more so than general
macroeconomic trends, affects heating demand. Overall power demand is generally correlated with GDP.
Separately, there is a secular shift away from coal-fired plants toward natural gas plants in North America, as
well as other regions, which is increasing the market share of natural gas power plants in the overall power
generation market. Industrial demand is the most cyclical, and can swing sharply depending on the economic
outlook.
• NGL demand: Demand for NGL tends to have a high correlation with industrial production. The petrochemical
and oil refining sectors represent large sources of demand. Some NGL demand relates to home heating needs,
which general economic trends affect less. In Canada, demand is highly correlated with bitumen production, as
NGL condensate is the preferred diluent to allow pipeline transport of heavy oil.
Changes in volume flows, either due to regional supply or demand changes
28. Changes in regional supply or demand can affect utilization rates of midstream infrastructure. In analyzing the
supply side, we consider a basin's size and cost structure. A mature basin may see declining production trends that
would translate into lower midstream throughput levels that serve that basin. A high-cost basin is more likely to see
curtailed drilling and throughput levels when commodity prices decline.
29. A number of factors can affect regional demand. At the extreme, a crude oil pipeline may serve a single refinery. If
the refinery shuts down, the pipeline would become useless. On the natural gas side, flows will depend on industrial
and residential demand in the market the pipeline services.
Competition and the risk of overbuild
30. Pipelines generally face less competition relative to other industry sectors because of the significant barriers to entry.
However, over time, changing industry dynamics can create greater competition. For example, three pipelines may
be sufficient to serve a specific producing basin at a certain point in time. Several years later, the basin's production
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may decline either due to its age or because its cost structure becomes higher than other basins. In that case, there
would be excess export capacity from the basin, and the pipelines could compete on price to maintain throughput
levels.
31. Other midstream segments tend to be more competitive. Capital costs associated with storage facilities and
processing plants are more modest, and can lead to overcapacity in certain markets. For example, natural gas
storage rates have fallen dramatically in recent years due to a combination of new supply coming on line and lower
end-user demand.
32. Propane and heating oil retail distribution represents the most competitive midstream segments. Barriers to entry are
low, and the industry is highly fragmented in the U.S. Thousands of small firms with one or two trucks compete
with the larger players.
Construction risk
33. The industry is capital intensive. Large-scale projects, such as long-haul pipelines, can cost well over $1 billion and
take several years to complete. Companies face the risk that projects cost more and take longer than originally
envisioned, which can strain balance sheets. Obtaining necessary rights-of-way and environmental permits may also
prove daunting. However, once projects are completed, the capital requirements create barriers to entry, decreasing
the risk of competitive threats.
Company-specific analysis
34. Once key country and industry risk considerations have been identified, including industry-specific key credit
factors, the credit analysis proceeds to company-specific analysis. The business risk part of this analysis is divided
into three parts:
• Company competitive position (including subcategories of market position, diversification, and operating
efficiency);
• Management assessment; and
• Profitability (which incorporates industry peer group company comparisons).
35. We evaluate each of the key credit factors within the competitive position subcategories for each segment of the
midstream industry to determine the company's relative competitive position. We then adjust, if necessary, the
competitive position with management assessment and profitability to determine the company's business risk profile.
Combining the factors to derive competitive position
36. The following Category 1 factors play the most important role in determining our view of competitive position in
the midstream energy sector:
• Resiliency of volume flows;
• Contract profile, specifically the type and length of the contracts and the creditworthiness of counterparties;
• Degree of commodity price exposure; and
• Scale and geographic diversity of operations
37. This section (paragraphs 36-50 )discusses how we combine these factors, as well as certain Category 2 and 3 factors
at times, in formulating overall competitive position scores. We then discuss them in more detail in paragraphs
48-87.
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38. Pipelines. Long-haul pipelines generally have competitive positions scored between "satisfactory" and "excellent".
These assessments reflect pipelines' generally low volume variability, minimal direct commodity exposure, and
contracted revenue streams.
39. "Excellent" pipelines typically have a distinguished competitive positive, as evidenced by a multiyear history of
stable throughput levels, which we would expect to continue in the vast majority of downside scenarios. A long
contract tenor--usually at least 10 to 15 years--can also support an "excellent" assessment, even if the underlying
competitive position is slightly less robust.
40. Pipelines with less favorable competitive position assessments (e.g., at the "satisfactory" level or potentially lower)
display higher, or potentially higher, volume variability. In the natural gas universe, these pipelines tend to be
"supply–push" and can see variability depending on geographic basis differentials or contracts that are set to expire
in the next five to seven years. For liquids pipelines, volume variability can also arise, or be exacerbated, if the
pipeline is poorly positioned (e.g., exporting crude oil from a mature, declining basin) or it is linked to refiners with
weaker competitive positions.
41. The competitive position assessments of companies' pipeline segments may be finally adjusted by scale and diversity,
as well as by the regulatory framework. Scale and diversity play an important role. As an example, a single refined
products or crude oil pipeline could have a higher risk assessment if it is exposed to a single refiner's health or a
declining field. A diversified pipeline portfolio mitigates this risk. Regulation may positively affect our assessments if
we believe it will insulate a pipeline's profits from higher operating costs and competition, but we generally consider
the impact to be minor.
42. Terminals and storage. Terminal and storage facilities generally have competitive positions scored between "fair" to
"satisfactory", though the potential range of assessments is broad. The general assessment reflects expectations that
throughput and rates remain fairly stable, although not as stable as the long-haul pipeline sector, and that direct
commodity price exposure is low.
43. Terminal and storage facilities may have better assessments if they have superior scale/geographic diversity, location,
and contract profiles. More favorable assessments are generally associated with larger, well-diversified portfolios of
terminaling and storage assets. In addition, we would generally favorably view supply/demand dynamics for most of
the assets and many would have contract lives of at least five years. Location may also be more favorable if there are
development restrictions, due to permitting or geography, on the building of competitive facilities. We also look
more favorably on those that have primarily utilities as customers, given their high renewal rates.
44. Facilities may have worse assessments if there is limited scale or significant geographic concentration, particularly if
we see risk of overbuild in the region or we expect demand to fall. We would typically also see a weaker contracting
profile, with most assets having shorter-term contracts, generally five years or less. A preponderance of
trading/marketing customers would also speak to a less favorable assessment, given their willingness to exit
contracts if market conditions become unfavorable.
45. Gathering, processing, and fractionation. The gathering, processing, and fractionation segments generally have
competitive positions scored between "weak" and "fair" due to the inherent volume risk and commodity price
exposure.
46. The gathering, processing, and fractionation segments may have more favorable competitive position scores (e.g.,
"fair" or potentially better) if they have very good scale and geographic diversity, operate in basins with favorable
characteristics, and have reduced commodity price exposure. We generally consider processing and, in some cases,
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fractionation less favorably than gathering because they often entail commodity price risk and have shorter
contracts. Well-positioned gathering, processing, and fractionation companies will have leading positions in at least
three basins (or potentially one to two basins if they display superior characteristics, such as a long reserve life and a
highly competitive cost structure) and have contract profiles that are mostly fee-based, have a tenor of at least five
years, and have "minimum daily quantity" (MDQ) contractual requirements that mitigate volume risk. Being
positioned in an area of strong "demand-pull" is also advantageous.
47. The gathering, processing, and fractionation segments may have less favorable competitive position scores (e.g.,
"weak" or potentially worse) if they have modest scale, limited geographic diversity, and contracts that expose the
company to commodity price risk. They will often have substantial positions in only one to two basins and have
contracts that do not provide multiyear volume protection or insulation against commodity price movements.
Contract types with greater commodity price exposure include keep-whole, percentage-of–liquids, or
percentage-of-proceeds (see paragraph 70).
48. Retail propane, crude oil, and heating oil marketing companies. Retail propane, crude oil, and heating oil
marketing companies generally have business risk profiles of "vulnerable" to "fair" due to generally fierce
competition, low barriers to entry, and weather risk. Assessments are primarily distinguished by scale and operating
efficiency. Companies with more favorable assessments are generally located in at least three distinct geographic
regions, at least partially insulating them from adverse weather patterns and regional competitive dynamics. They
also have stronger operating efficiency measures (e.g., gross profit or operating expense on a per-customer or
per-gallon basis). We have less favorable assessments on those with smaller footprints and less competitive operating
efficiency measures, as they will be more vulnerable to regional weather patterns and competition.
49. Diversified. Diversified midstream companies have the full range of potential competitive position assessments, from
"vulnerable" to "excellent". The assessment depends primarily on the business mix and the operations' scale and
geographic diversity. The preliminary assessment on the enterprise stems from weighting the business risk
assessments of its operating segments by expected EBITDA contribution. For example, a diversified company with
most of its EBITDA coming from contracted long-haul pipelines will have a more favorable assessment than a
diversified company with a majority of its EBITDA coming from commodity price-exposed gathering, processing
and fractionation operations, everything else being equal. To achieve a "satisfactory" or better assessment, we
generally expect diversified companies to have at least two-thirds of EBITDA (in a normalized pricing environment)
as fee-based
50. The preliminary competitive position assessment is then refined by scale and geographic diversity. Scale and diversity
can play a significant role, but are required to be particularly impressive for companies with a majority of
nonfee-based EBITDA to be assessed as "satisfactory" or better. Companies can achieve more favorable assessments
when they expand their service offerings and geographic footprint because of the diversification benefit, better
economies of scale, and the ability provide customers a fuller set of product offerings. When weighing the impact of
scale and diversification, we do so in the context of how volatile consolidated operating profits are. If the company
achieves greater scale and diversity while maintaining the same percentage of fee-based EBITDA, we would have a
more favorable view of its business risk assessment. Conversely, if it did so while significantly increasing its
commodity price exposure, the greater profit volatility could outweigh the improved scale and diversity, leading to a
less favorable assessment. A final consideration is the scalability of its growth-related capital spending program (see
paragraph 89). If capital projects introduce greater construction risk and cash flow lag, the business risk assessment
can also suffer.
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Key risk factors of competitive position
51. We consider the key credit factors outlined at the beginning of this report as being important in evaluating the
competitive position of companies in the midstream energy industry.
52. Market position. In analyzing market position for a midstream company, we usually consider the following key
credit factors (from most to least important) as part of the ratings process:
• Resiliency of volume flows (Category 1);
• Contract profile, specifically contract length and counterparties' creditworthiness (Category 1);
• Degree of commodity price exposure (Category 1);
• Operating scale and geographic diversity (Category 1); and
• Regulatory framework under which the midstream energy companies operate (Category 2).
Category 1 factor-Resiliency of volume flows
53. Generally speaking, customers pay fees to midstream companies to use, or have the right to use, their assets.
Potential revenue variability will depend on customers' willingness to continue to use the assets. At one end of the
spectrum, certain long-haul pipelines play a critical role in connecting supply sources to demand centers, and have
little throughput volatility. They have multiyear track records of stable volume flows through different commodity
price and economic cycles. At the other extreme, gathering lines located in a mature basin or one with a relatively
high cost structure could see annual double-digit volume declines.
54. Pipelines. The natural gas long-haul pipeline sector can often be categorized as "demand-pull" and "supply-push."
Demand-pull pipelines serve utilities and utilization rates and tariffs generally vary little. Electric and gas utilities
place a high priority on how well they deliver sufficient gas supplies to their power plants or customers during
extreme weather, and seek to maintain sufficient pipeline capacity to do so. Supply-push pipelines export
hydrocarbons from specific basins, generally to an interconnection point, often referred to as a market hub. In turn,
the hydrocarbons flow via other pipelines to end-users. Throughput levels on these pipelines are more susceptible to
changes in geographic basis differentials. For example, it would make little sense to transport gas from point A to
point B if the transportation cost were 50 cents per dekatherm and the basis differential (point B price minus point A
price) were 40 cents. Not all natural gas pipelines can be neatly categorized as supply-push or demand-pull. Some
have a shipper mix that includes utilities as well as producers and marketers.
55. Refined product pipelines transport gasoline, diesel, jet fuel and heating oil from refineries to consuming areas. Some
refined products pipelines play a critical role in a country's infrastructure and maintain excellent competitive
positions. For example, there are only a few long-haul pipelines that transport products from the U.S. Gulf Coast
region, where the country's refining capacity is concentrated, to the Northeast. They generally provide the lowest
cost means of transporting the products and have seen little demand fall-off in economic downturns, although
weather events, like hurricanes, can temporarily shut down refineries and, thus, supply. However, refined product
pipelines designed to export products from a single refinery have their health tied to that refinery. If it is idle or
closed for a long time, the pipeline can become useless.
56. Crude oil pipelines generally see stable throughput levels, but are subject to depletion risk over time. The degree of
depletion risk can hurt the business risk assessment. For example, we generally regard the onshore California region
less favorably because it is a very mature basin and pipelines servicing the area have had year-over-year percentage
throughput declines in the single digits. However, operators in the Canadian oil sands regions expect to grow
production for many decades, ensuring high use of well-positioned pipelines that transport crude out of the area.
Key considerations are the field life and the susceptibility of throughput drops due to unscheduled downtime or bad
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weather.
57. Terminals and storage facilities. Terminal and storage facilities generally have stable throughput levels during
economic and commodity price cycles. Asset-by-asset, however, relative throughput stability varies. Some facilities
will have more exposure to geographic basis differentials and time spreads and have more rate and throughput
variability, which we view less favorably.
58. Location is critical for the asset class. We have a more favorable view of those assets situated at key trading hubs,
that have good connectivity to pipeline networks or that are near end-users. Also positive are value-added services
beyond simple physical storage. For example, oil storage facilities with good connectivity that segregate and mix a
wide slate of crudes can provide their refinery customers more optimal feedstock, supporting revenues even if the
forward curve is flat to down. Similarly, more sophisticated refined products terminals may be able to earn premium
margins as environmental requirements have led to greater diversification of product specifications.
59. Customer mix is important. We have a better view of end-use customers because they're more concerned with
reliability and likely to renew contracts, although rates may go down if the market declines. Conversely, trading and
marketing companies generally use these facilities to profit from volatile market opportunities. When prices are
volatile, there is market contango, and geographic basis differentials are wide, these customers will demand these
facilities. However, if market conditions change and these trading opportunities evaporate, they may not renew
contracts.
60. Terminal and storage facilities present greater risk than long-haul pipelines because there are fewer barriers to entry.
The sector faces greater risk of overcapacity in specific regions and competition can drive down profits. For
example, in recent years, the natural gas storage sector has had more volatile rates relative to liquids storage. Many
natural gas storage facilities were recently built when demand, particularly for salt dome storage caverns, fell due to
low natural gas prices, narrow basis differentials, and low price volatility.
61. Gathering, processing, and fractionation. The amount of drilling drives how much gathering lines and processing
plants get used, as well as shorter intrastate pipelines. Drilling in a given basin can decrease due to lower
hydrocarbon prices, worse-than-expected reservoir quality, the advancing age of the basin, and a number of other
reasons. When drilling falls, production--and thus throughput--generally falls sharply in the initial years and further
decreases thereafter at a slower rate.
62. We have a more favorable assessment of gathering and processing companies when they are in basins with low
inherent cost structures, have a mix of NGLs and natural gas (the prices of which are not well-correlated, thus
providing producers a diversification effect), and multiyear drilling inventories. Our assessment is less favorable
when the basin has a higher inherent cost structure, is mostly "dry" gas (i.e., the reservoir yields little NGLs), or has
matured such that drilling will likely decline in the coming five to 10 years.
63. Fractionation plants, where NGLs are broken into the individual purity products (ethane, propane, butane,
isobutane, and pentane), are generally at a small number of locations, referred to as hubs, in North America.
Utilization is less a function of drilling levels in specific basins, but more by NGL end-user demand and the amount
of a region's fractionation capacity. In Alberta, there are a series of large fractionation plants in the Fort
Saskatchewan area, which is a major petrochemical hub. The facilities service these petrochemical clients, and are
major suppliers of ethane for ethylene production. We would characterize the tight integration as a demand-pull for
fractionated products.
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64. Retail propane, crude oil, and heating oil marketing. Retail propane and heating oil distributors can witness
volume decline due to competition, customer conservation, mild weather, and customer conversions to natural gas
heating. Many rated companies have had a multiyear trend of fewer customers served and lower volumes. While
these risks affect all companies in the sector, companies with good customer service tend to have lower customer
churn, and thus more stable volumes.
Category 1 factor--Contract profile
65. Long-term contracts with creditworthy counterparties can enhance credit quality by insulating assets from market
price fluctuations during a contract's duration. These contracts are tightly written, leaving little room to terminate
or renegotiate if customers are in out-of-the-money positions. When assessing contract profiles, the key variables are
the contract tenor, the type of customer (and rating), and potential for margin volatility in the contract terms.
66. In terms of contract type, "take-or–pay" contracts are most prevalent in the sector. They require the customer to
make payments regardless of whether they use the assets, which we view favorably. In some emerging markets,
however, contract culture has not yet been well established and renegotiation risk might be considerable even for
take-or-pay contracts. If a company operates in such an environment and its customers have incentives to
renegotiate, then we would view such contract positions to be neutral or potentially negative for credit quality.
"Take-and-pay" contracts, on the other hand, do not obligate the customer to make a payment if it does not use the
capacity. As such, these contracts are far less favorable from a credit perspective.
67. Cost-of-service contracts are frequently seen in Canada, but are rare in the U.S. These contracts permit the
midstream operator to receive a return on capital charge and some or all of operating and maintenance expenses.
We consider such contracts favorably.
68. Well-positioned natural gas interstate pipelines can have contracts with lives of more than 10 years. Storage
contracts tend to have contract lives in the three- to five-year area in the U.S. and five to10 years in Canada.
Well-managed companies will stagger maturity dates to lessen risk of renewing many contracts in trough market
conditions.
69. Customer type provides insight into the likelihood of contract renewals. Utilities have high renewal rates. Their
principal incentive is to be able to provide their customer base sufficient electricity and gas supply during adverse
weather. Energy marketing and trading companies, in contrast, will only renew if market conditions are favorable.
We will also consider cash flows from the contracts to only be as dependable as the credit quality of the
counterparties. However, extenuating circumstances can exist. For example, we would consider a pipeline that
transports natural gas into a utility's service territory to be a critical supplier. Even if the utility declares bankruptcy,
the utility would still require the pipeline to serve its customer base. Assuming contracts are at market rates,
revenues may not go down, although we would still consider the risk that payments become delayed in this scenario.
70. Not all contractual revenue is stable and it may vary, depending on contract terms, with delivery volumes or
commodity prices. In natural gas processing and extraction/fractionation, there are five general contract types that
dictate the midstream company's level of commodity price exposure:
• Cost of service: Receive a return of capital charge, and some or all of operating and maintenance expenses, and
are volume independent.
• Fee based: Receive payment per unit of throughput.
• Percentage of liquids: Receive some of the extracted NGLs with no exposure to natural gas.
• Percentage of proceeds: Receive some of the residue natural gas and NGLs at index-related prices.
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• Keep-whole: Receive natural gas from a producer, process the gas, and keep the extracted NGLs. The midstream
company returns to the producer an amount of residue gas that is equal in terms of Btu value.
71. Contracts will often be a blend of the five contract types. For example, a percentage of proceeds contract may have a
floor price, protecting the midstream company if commodity prices fall to low levels.
72. We consider cost-of-service and fixed-fee take-or-pay contracts to be the most favorable for credit quality. Second
are fee-based contracts linked to volumes, sometimes called take-and-pay contracts. Cash flows are subject to lower
throughput, but are not directly exposed to commodity prices. Considerably more risky are contracts that directly
expose a midstream company's revenue stream to volatile commodity prices, such as the percentage-of-liquids or
-proceeds contracts mentioned above. We consider keep-whole contracts to be the least favorable because they
expose companies to the spread between liquids and natural gas prices (effectively, the midstream company is long
NGLs and short natural gas). If the spread narrows, profits will suffer. Historically, keep-whole margins have gone
negative, although such occurrences are rare.
Category 1 factor--Degree of commodity price exposure
73. Greater commodity price exposure translates into more volatile cash flow. A midstream company with a favorable
assessment will have a low percentage of its EBITDA sensitive to commodity prices; one with a less favorable
assessment will have a high percentage of its EBITDA sensitive to commodity prices.
74. Single-asset pipelines and storage terminals generally have the vast majority (90%-plus) of their EBITDA insensitive
to commodity price swings. Typically, the only exposure relates to a pipeline's ability to maintain 1/100 of 1% of
commodity throughput for its own account, which it can offset against any volumes lost during the normal course of
business. Well-run pipelines with minimal losses can consistently generate revenue streams from this provision, but it
is generally still a small amount.
75. While storage and terminaling operations also earn the vast majority of fees from fee-based activities, they can have
some commodity price exposure. In some cases, they offer some value-added services (e.g., butane blending) for
customers whose profit opportunity will fluctuate with commodity prices. In other cases, storage companies can use
their assets to execute trade strategies to take advantage of temporal spreads (e.g., when futures prices exceed spot
prices plus storage costs) or geographic pricing differentials. Because the cash flows from such activities are not
recurring in nature, we generally discount their future cash flow contributions in our financial projections. When
companies engage in such activities, we assess risk tolerance and internal controls, as discussed below in the
financial policy section.
Category 1 factor--Scale and geographic diversity of operations
76. Larger, geographically diverse companies tend to have stronger business risk profiles. Such companies enjoy better
operating flexibility and economies of scale. A geographically diverse portfolio provides natural protection against
risk factors (e.g., regional price dislocations or a given basin's geological quality) that may affect one region more
than another.
77. For diversified midstream energy companies, to be commensurate with a "satisfactory" descriptor, we would expect
EBITDA of at least several hundred million dollars and exposure to at least three distinct geographic areas. There
are several single-asset pipelines that are exceptions. Such companies or joint ventures generate very stable, fee-based
cash flows due to either a unique competitive position, making volume flows resilient in various downside scenarios,
or a long-dated contract profile with creditworthy counterparties.
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Category 2 factor--Regulatory framework
78. Rate regulation can support credit quality in the midstream energy sector. Regulatory systems differ across
countries. In the U.S. we generally consider such support to be modest, but it can be an important positive factor for
some long-haul pipelines in the Commonwealth of Independent States (CIS, or Russia) as an example.
79. In the U.S., the Federal Energy Regulatory Commission (FERC) regulates tariffs for interstate pipelines and
associated storage facilities with the goal that rates be "just and reasonable." State regulators (e.g., the Texas
Railroad Commission) regulate intrastate pipelines, although they often rely on FERC guidelines. Regulation can
mitigate cash flow volatility for pipelines, but the degree of protection is considerably less compared with the state
public utility commissions that regulate electric, gas, and water utilities.
80. For interstate natural gas pipelines, the FERC establishes maximum allowed tariffs that permit a pipeline to achieve
an allowed after-tax return on equity in the 12% area, although allowed returns will vary case by case. Pipelines
subsequently can file a rate case when profitability declines, for example, due to lower utilization levels or higher
operating costs. Conversely, if the pipeline becomes too profitable, the shippers or the FERC itself can initiate a rate
case with the goal to decrease rates. In reality, rate cases tend to be infrequent, and pipeline and shippers generally
settle their disputes via negotiated settlements. Actual returns on equity have varied materially, with some being
more than 20% on a multiyear basis and others below 10%. Finally, pipeline operators frequently enter into
long-term contracts with shippers at rates below the maximum permissible rates that the FERC established.
81. This regulatory framework reduces the risk of lower profits in situations where there are moderate adverse changes
to operating costs or throughput levels. However, if the pipeline's competitive position materially worsens, causing a
large number of shippers to leave the pipeline, we believe that the FERC would not permit the pipeline to materially
increase rates to remaining customers because they would no longer be just and reasonable. Furthermore, from the
pipeline's perspective, such an increase could cause a vicious circle in which other shippers elect not to renew
contracts as they mature.
82. The FERC regulates interstate crude oil and refined products pipelines differently. It does not have a return on
equity methodology, but regulates the extent to which maximum permissible tariffs can increase in noncompetitive
areas. In those areas, the FERC generally allows carriers to increase their maximum rates within ceiling levels that
are tied to an inflation index. We consider the protection that FERC regulation provides to liquids pipelines to be
less robust relative to the natural gas sector because a defined return on equity is not targeted. In the U.S., other
midstream sectors--terminals, independent storage facilities, gathering lines, and processing facilities--are not subject
to rate regulation.
83. We generally view Canadian regulation more favorably because it provides pipeline operators greater protection
against falling volumes. Interprovincial and international pipelines in Canada fall under federal regulation by the
National Energy Board (NEB). Intraprovincial pipes are governed by their respective provincial regulators and tend
to follow the same general principles and methodology. The Canadian regulatory compact is strong in our view and
generally relies on a cost-of-service model that allows for the return of all prudently incurred costs, including a
return of, and on, capital. Volume risk is mitigated by rolling over underrecovered costs of the previous year into the
forward year's adjusted revenue requirement and tariff. Full, forward-looking cost-of-service applications are
typically filed every three years. Allowed returns are currently lower than those allowed by the FERC, reflecting this
low-risk regulatory regime. Regulated returns have, in the past, met the requirements for the regulator's fair return
standard, without regard for toll impacts. NEB regulation is typically light-handed and allows for negotiated
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settlements between pipe owners and shippers, although the regulator must approve the final contract. Without an
agreement, the pipe owner has recourse to filing an application for regulated rates.
84. In the CIS, we generally consider regulation in the midstream energy sector favorably. While opaque, pipeline
operators in countries like Russia and Kazakhstan have a long track record of increasing tariffs to maintain
adequate profitability. In Russia, the Federal Tariff Service permits oil and natural gas pipeline operators to set
tariffs based on a projected budget and operators can revise tariffs if costs increase. Refined products pipelines,
however, set tariffs that are capped at 70% of those on railway transportation for the same routes. While there are
structural differences, both regulatory approaches allow pipeline operators to generate adequate investment returns.
As a practical matter, a company's relative bargaining position vis-à-vis the regulator and its counterparties plays a
more important credit consideration. Under Russian law, only state-owned entities can operate (with relatively rare
exceptions) long-haul oil and gas pipelines, and the government must approve new pipeline construction. As a result,
the midstream sector has significant barriers to entry, which we view favorably for existing operators.
Category 3 factor--Diversification/integration with other business lines
85. Integration with other business lines can add or detract from our assessment of a midstream company's competitive
profile, depending on the nature of the other business lines and the correlation between them. A favorable
assessment reflects an integration model that enhances the company's scale and product offerings, while allowing the
company to maintain a mostly fee-based revenue model and acceptable return on capital measures. Conversely, an
unfavorable assessment reflects an integration model that increases the company's commodity price exposure
without materially improving its scale and product offerings.
86. Examples of such integration/diversification include:
• Oil and gas E&P,
• Oil refining,
• Retail gasoline stations with associated convenient stores,
• Marine transportation and seaport terminals, and
• Petrochemicals.
87. Because many midstream energy companies employ a predominantly fee-based business model, the diversification
into more volatile industries like oil and gas E&P, oil refining, and petrochemicals most commonly increases a
company's business risk, as the percentage of EBITDA with commodity price exposure grows.
Operating efficiency
88. In analyzing operating efficiency for a midstream company, we usually consider the following factors (from most to
least important) as part of the ratings process:
• Scalability of growth-related capital spending program and characteristics of maintenance capital spending
(Category 2 factor), and
• Cost profile of operating assets (Category 3 factor).
89. Category 2 factor--Scalability of growth-related capital spending program and characteristics of maintenance
capital spending. Many midstream energy companies invest in large, multiyear growth projects. Such spending
programs can hurt companies' credit profiles due to construction risk and cash flow lag (i.e., the company
immediately incurs debt to fund a project but does not receive cash flows until project completion). We have seen
many programs grossly exceed their initial budgets due to higher commodity prices, engineering changes, labor
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inefficiencies, and adverse weather. In assessing the potential for cost overruns, we analyze the project type, the level
of risk the engineering and construction company assumes, mitigants in place (e.g., whether management has
already purchased raw materials at a fixed price), and the company's experience with building similar projects.
Other companies focus more on investing in smaller discrete projects, which we assess more favorably. This
approach has inherently lower risk because dollar amounts are lower and time tables shorter.
90. Maintenance capital spending tends to be relatively modest for midstream operators. However, we expect such
spending to increase in the future due to a greater focus on pipeline integrity. A company's track record of properly
maintaining assets and ensuring good safety records serve as good leading indicators for operational risks.
91. Category 3 factor--Cost profile of operating assets. In many cases, comparative analyses of pipelines' and storage
facilities' cost metrics yield limited value because assets serve specific markets without facing direct competitors. For
example, if there are no or few alternatives to supply natural gas to a specified market, a pipeline serving such an
area will likely earn a fair return even if its operating expenses on a throughput basis are high. Furthermore,
diversified midstream companies often do not provide detailed cost disclosure on an asset-by-asset basis.
92. When disclosure is sufficient, comparative cost analyses can add value. For example, if two companies operate
similar storage facilities near the same location, operating expense per unit of storage capacity becomes an
important distinguishing metric. The profitability of the lower cost facility should be more resilient in a downturn.
Regarding pipelines, if a utility has two natural gas pipelines connect into its service territory from different supply
basins, the pipelines' operating expenses can differentiate their competitive positions. The utility will seek the lowest
supply source. In an idealized example, if the cost of extracting natural gas in the two basins is the same, the pipeline
with lower costs should see higher utilization. In reality, the costs of extracting natural gas will differ, making the
analysis more complex. Furthermore, the pipelines would likely serve several markets along their routes, and utilities
have incentives to have redundant supply sources.
93. Propane distribution represents the one subsegment in the midstream sector where companies' cost profiles are of
paramount importance. Because of thin margins and little product differentiation, cost structures are key
profitability determinants. We generally track operating expenses on a per-gallon and per-customer basis.
Management and strategy
94. Most U.S.-based midstream companies are incorporated as MLPs. They are limited partnerships that trade publicly
on a U.S. securities exchange, and enjoy favorable tax treatment by avoiding the corporate income tax. In Canada,
most midstream companies are corporate entities, and are not subject to the MLP governance risks outlined below.
95. We generally have less favorable assessments of MLP corporate governance provisions because limited partner
unitholders have very limited voting rights. In a typical partnership agreement, an MLP's equity is divided between a
2% general partnership (GP) interest and a 98% limited partnership (LP) interest. The GP has broad authority to
manage the partnership and usually also has incentive distribution rights (IDR), under which it's entitled to higher
percentages of available cash flow as the MLP increases its distributions. LP unitholders are intended to be purely
passive investors. The board is elected by the GP unitholders, and its main fiduciary responsibility is to the GP.
While partnership agreements typically have terms that allow LP unitholders to remove the GP, in practice it is
difficult.
96. More favorable assessments of corporate governance practices can exist, although they are relatively infrequent in
the MLP universe. Certain MLPs have changed partnership agreements to improve corporate governance practices
and processes. One innovation collapses the GP into the MLP, extinguishes IDRs, and has a single board of
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