Tailoring Hydrocarbon Price Assumptions To The Canadian Oil And Gas Industry

Transcription

1 Tailoring Hydrocarbon Price Assumptions To The Canadian Oil And Gas Industry Primary Credit Analyst: Michelle S Dathorne, Toronto (1) ; michelle.dathorne@spglobal.com Research Assistant: Anuj Navare, Pune Table Of Contents Canadian Crude Oil Prices Heavy Oil Price Differentials Pricing Canadian Natural Gas Emerging Market Hubs Support Future Development Many Factors Create A Credit Profile JANUARY 9,

2 Tailoring Hydrocarbon Price Assumptions To The Canadian Oil And Gas Industry S&P Global Ratings' assessment of an oil and gas company's creditworthiness incorporates a number of factors affecting the company's business and financial profiles. Crude oil is a highly fungible, global commodity, and as such, to assess it we consider both global and regional factors. Natural gas is inherently a regional commodity, given its more limited transportation options. However, expanding liquefied natural gas production, transportation, and re-gasification capabilities could put natural gas on a global platform in the longer term. We incorporate global and regional industry factors, in conjunction with myriad company-specific business and financial factors, into our assessment of an oil and gas company's credit profile. Realized oil and gas prices, which S&P Global Ratings will adjust to reflect regional supply and demand fundamentals, and the transportation links between producers and end markets are the most important inputs underpinning our revenue and cash flow forecasts for oil and gas exploration and production (E&P) companies. We consider these factors under both our global corporate methodology and industry-specific Key Credit Factors criteria to assess a company's credit profile and ratings. Our hydrocarbon price and company-specific cost assumptions are the primary input into our cash flow forecasts for oil and gas producers. We then adjust our published global and U.S. benchmark price assumptions to reflect local pricing dynamics. For Canadian oil and gas producers, we convert our West Texas Intermediate (WTI) crude oil and NYMEX natural gas price assumptions to the appropriate equivalent benchmark price, taking into account relevant supply/demand fundamentals, basis differentials, and foreign exchange rates. Overview For oil and gas companies, realized hydrocarbon prices are the most important factor affecting their cash flow and leverage, and overall financial risk profiles. Our assessment of Canadian oil and gas companies' credit profiles also incorporates regional factors. In our price assumptions, we consider supply/demand fundamentals, basis differentials, and foreign exchange rates. Table 1 Standard Assumptions Edmonton Par discount to West Texas Intermediate (%) 0 Western Canada Select discount to West Texas Intermediate (%) 25 AECO differential to Henry Hub (US$/MMBTU) 0.50 Canadian Crude Oil Prices Canada's crude oil production ranges from light to heavy oil, with Canadian prices linked to the U.S. benchmark WTI crude oil price. Pricing fundamentals ultimately depend on market demand and supply factors, such as transportation JANUARY 9,

3 links to processing and refining hubs configured to process the crude. Price differences that remain closely aligned with transportation costs indicate highly efficient and balanced markets. Price differences between the Edmonton Par Canadian light crude oil price and WTI tend to be fairly stable, with the basis differential typically converging to the unit transportation costs (see charts 1 and 2, and table 2). As a result of fairly stable Canadian light oil production levels and pipeline capacity into U.S. markets, material top-line adjustments to our WTI price assumptions are rarely required for the Edmonton Par price. We typically capture the basis differential (or unit transportation costs) as a component of an E&P company's total cash operating costs. Chart 1 Chart 2 Table 2 Differentials Range Parameter West Texas Intermediate-Edmonton Par (US$/bbl) Differential as % of West Texas Intermediate Minimum (6) (6) Maximum Average 5 6 Median 4 6 Source: Bloomberg. Heavy Oil Price Differentials The Canadian Association of Petroleum Producers' June 2016 crude oil forecast estimates total daily average in-situ oil sands bitumen production at about 1.4 million barrels of Canada's estimated 2016 daily average total crude oil production of 3.8 million barrels. As increasing bitumen production is expected to fuel Canada's long-term crude oil production growth, the Western Canada Select (WCS) price, the benchmark price for Canadian heavy oil, will increasingly determine Canadian producers' future revenues and cash flow generation. For the rated Canadian E&P companies producing heavy oil, the WCS price significantly affects profitability and cash flow metrics. Bitumen sells at a discount to WTI, due to the quality discount associated with its lower API gravity relative to light oil. When JANUARY 9,

4 forecasting revenue and cash flow for Canadian bitumen production, our base-case forecasting assumptions include an explicit WCS differential, as a percentage of our WTI price assumption. When warranted, we will adjust our uniform WCS discount assumption on a company-specific basis, if we expect a company's realized bitumen price to consistently deviate from our standard differential assumption. In the past, the heavy oil price discount historically averaged about 30% off WTI, reflecting the quality discount as well as constrained transportation capacity to U.S. refineries configured to process heavier crude oil feedstock. As transportation options and capacity increased, the differential narrowed (see charts 3 and 4 and table 3). Chart 3 Chart 4 Table 3 Differentials Range Parameter West Texas Intermediate-Western Canada Select (US$/bbl) Differential as % of WTI Minimum 7 11 Maximum Average Median Source: Bloomberg. As WTI prices continued falling through 2015 and the first half of 2016, the absolute dollar value of the discount decreased to a minimum level, which roughly equates to transportation costs. The minimum WTI-WCS discount has averaged about US$10-US$14 per barrel, depending on the transportation option used to move the heavy crude. At our current published WTI price assumptions for , we believe the WCS price discount should remain consistent with transportation costs, and, by extension, roughly equate to the current 25% WTI-WCS discount assumption we typically use relative to our published WTI price assumptions for our forecast years. If Canada's future bitumen production growth outpaces transportation capacity expansions, the Canadian heavy oil price discount could once again increase above transportation costs. We believe this risk is beyond our current three-year ( ) cash JANUARY 9,

5 flow forecasting period. Generally, heavy oil price differentials will experience periods of heightened volatility during times of supply, transportation, or refining capacity disruptions. When bitumen feedstock supply exceeds either transportation or refining capacity capability, or both, the heavy oil price discount will increase, reducing the realized price for Canadian heavy oil. Conversely, curtailed heavy oil production, relative to stable transportation and refining capacity, will increase heavy oil realized prices. Pricing Canadian Natural Gas The natural gas markets in Canada and the U.S. are often described as integrated with one another, as the regional natural gas markets in the two countries are well connected by pipelines. This continental integration allows the supply-demand fundamentals to be transferred across all markets. Moreover, Canadian natural gas production remains much higher than domestic consumption. The Western Canada Sedimentary Basin (WCSB) is the major hydrocarbon basin in Canada and accounts for 95% of Canada's and 24% of North America's natural gas production. The AECO Hub natural gas storage operation is located in Alberta, and is owned and operated by Niska Gas Storage. It consists of two gas storage facilities, AECO Suffield (southeastern Alberta) and AECO Countess (southcentral Alberta), both of which are connected to the TransCanada Pipelines Alberta System. With a total working gas capacity of 154 billion cubic feet (Bcf), the AECO hub clears substantially all of Canada's 15.2 Bcf/day of natural gas production. With the majority of Canada's natural gas production moving through Alberta's AECO hub, the AECO price has long been Canada's equivalent benchmark price to the U.S. Henry Hub NYMEX natural gas benchmark price. Adequate storage at the AECO hub and sufficient pipeline capacity have historically kept the basis differential largely consistent at about 50 U.S. cents; however, increasing U.S. domestic natural gas production from regions like the Marcellus and Utica shales, and an expanding U.S. natural gas pipeline network, with the potential to move up to an incremental 16 bcf per day through the lower 48 states has the potential to increase volatility to the basis differential and Canadian benchmark price (chart 5 and table 4). JANUARY 9,

6 Chart 5 Table 4 Differential Range (US$/MMBtu) Parameter Henry Hub-AECO Minimum (0.67) Maximum 1.65 Average 0.48 Median 0.46 Source: Bloomberg. Based on the observed historical basis differentials between the U.S. Henry Hub and Canadian AECO prices, we have a long-standing 50 U.S. cents/one million British thermal units (MMBtu) differential assumption we typically use when forecasting natural gas revenues for Canadian E&P companies. We will then make additional adjustments, as needed, on a company-specific basis to reflect other factors affecting realized prices, such as quality-related premiums and discounts, and hedges in place. Although we believe the shifting supply dynamics in North America due to increasing U.S. domestic natural gas production and an expanding pipeline network in the lower 48 states could affect the long-term basis differential, we are maintaining our existing 50 U.S. cents/mmbtu discount assumption in our revenue and cash flow forecasts for Canadian natural gas producers. JANUARY 9,

7 Emerging Market Hubs Support Future Development Expanding exploration and development activity in British Columbia, specifically the Montney, Liard, and Horn River basins, is increasing the importance of the pricing hub, Station 2, serving these regions. Station 2 is located near Chetwynd, B.C., and is the main aggregation point for supplies from the northeastern part of the province. Pipeline connections through Spectra Energy's Westcoast Energy pipeline system and the Alliance pipeline in B.C. collectively move the region's natural gas production through North Dakota, Minnesota, and Iowa and deliver gas to Chicago. Although the Station 2 hub is gaining prominence due to development activity from companies like Canbriam Energy, Crew Energy, and Seven Generations Energy, the hub remains far less liquid than the AECO hub. As a result, market prices for natural gas moving through Station 2 exhibit far greater volatility than typically realized with AECO natural gas prices relative to AECO's U.S. benchmark equivalent (see chart 6 and table 5). Chart 6 Table 5 Differential Range (US$/MMBtu) Parameter Henry Hub-Station 2 Minimum (0.15) JANUARY 9,

8 Table 5 Differential Range (US$/MMBtu) (cont.) Parameter Henry Hub-Station 2 Maximum 1.37 Avg 0.63 Median 0.62 Source: Bloomberg. The smaller size of Station 2 relative to the AECO hub results in pricing differences that require additional revenue adjustments for the Canadian E&P companies moving production through the Station 2 hub (chart 7 and table 6). This hub's smaller size and liquidity profile create greater pricing volatility than what typically occurs at the AECO hub. As a result, our revenue and cash flow forecasts for producers operating in this market can vary from year to year more than for AECO hub users. Chart 7 JANUARY 9,

9 Table 6 Differential Range (US$/MMBtu) Parameter AECO-Station 2 Minimum (0.62) Maximum 0.46 Average 0.16 Median 0.16 Source: Bloomberg. Many Factors Create A Credit Profile S&P Global Ratings considers a number of qualitative and quantitative factors in its credit analysis. Management's strategic planning process, operating effectiveness, and ability to adjust its business plans as market dynamics change are key considerations in our assessment of a company's overall business risk profile. For oil and gas companies, realized hydrocarbon prices are the most important factor affecting their cash flow and leverage, and overall financial risk profiles. We have adjusted, and will continue to adjust, our global and North American hydrocarbon price assumptions to reflect the local factors affecting Canadian oil and gas producers. JANUARY 9,

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