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The first article of the series has introduced the Carbonate Triangle of the renowned Canadian oil sands. The region is the world's third largest oil reserve with its rich carbonate-hosted bitumen deposit located in the northern Alberta's deep underground. Precisely, the Carbonate Triangle is situated between three major bitumen areas, Athabasca, Cold Lake and Peace River.

The last article reviewed Suncor Energy's (NYSE:SU) rich history, its current management strategy, two of its innovative processes, TRO and ZLD, developed by the company, as well as Suncor's oil sands mining operations and in-situ operations.

In today's investment guide on the Carbonate Triangle, I will review briefly the main characteristics of the Athabasca area with the objective to provide the most complete information available to potential investors before deciding to seize the opportunity that the 54,132 square miles of the Carbonate Triangle has to offer.

Then, the last part on Suncor Energy will discuss the current projects under development and those planned for the future. Then, I will examine the core financials of the company to assess its overall play in the Athabasca region as well as its positioning for a potential investment. So far, I looked into several producers involved in Peace River and Cold Lake regions of the Carbonate Triangle:

Peace River's most notable producers:

  1. PennWest Exploration (NYSE:PWE), see article here.
  2. Royal Dutch Shell (NYSE:RDS.A), see article here.
  3. Baytex (NYSE:BTE), see article here.
  4. Strata Oil and Gas (OTCQB:SOIGF), see article here.
  5. Petrobank Energy & Resources (OTCPK:PBEGF), see article here.

Cold Lake's most notable producers:

  1. Husky Energy (HUSK.PK), see article here.
  2. Pengrowth Energy Corporation (NYSE:PGH), see article here.
  3. Southern Pacific Resource (OTCPK:STPJF), see article here.
  4. Canadian Natural Resources (NYSE:CNQ), see article here.
  5. Devon Energy (NYSE:DVN), see article here.
  6. Imperial Oil (NYSEMKT:IMO), see article here.
  7. Baytex, see article here.
  8. Bonavista Energy (OTCPK:BNPUF), see article here.

Athabasca's most notable producers:

  1. Suncor Energy (Part 1), see article here.

Let's start by reviewing briefly Athabasca, a famous and most prolific region in the Canadian oil sands, as well as one of the largest reserves in the world.

Athabasca Region

Source: ERCB

The Athabasca oil sands are named after the Athabasca River, which cuts through the heart of the deposit, and traces of the heavy oil are readily observed on the river banks. Commercial production of oil from the Athabasca oil sands began in 1967, when Great Canadian Oil Sands Limited, now incorporated into an independent company known as Suncor Energy, opened its first mine, producing 30,000Bls/d of synthetic crude oil.

The Athabasca region can be defined with two major oil sands deposits: the Grosmont Formation and the Wabiskaw-McMurray Formation. The Grosmont Formation is a late-Devonian shallow marine to peritidal platform carbonate consisting of four recognizable units within the deposit. All of the hydrocarbons are located in an updip position, structurally trapped along the erosional edge and contained by the overlying Clearwater Formation.

Source: ERCB

The McMurray Formation was deposited on an exposed karstic landscape of ridges and valleys and varies in thickness from being absent over Devonian highs to over 426 feet thick in the Bitumont Basin. Bitumen-rich reservoirs formed within estuarine valleys stacked above the Lower McMurray channel sands and are assigned to the Upper McMurray Formation.

The bitumen pay thickness map of the Wabiskaw-McMurray deposit based on cutoffs of 6% mass and five feet thickness. In this map, the deposit is treated as a single bitumen zone and the pay is accumulated over the entire geological interval.

The Athabasca region is estimated to hold total reserves of 1.34 trillion barrels of oil. Approximately 8-10% would be recoverable with current technology, which would represent a total reserve of 134 billion barrels. Compared to the estimated 7 billion barrels contained in Peace River and approximately 16 billion barrels in Cold Lake, the Athabasca region is the most prolific and the most promising of the three, located in the Carbonate Triangle.

Oil Sands Ventures and Projects Outlook

Suncor actively develops some of its most promising projects in the oil sands area. Here is a brief description for each of them.

Fort Hills Mining Project

Source: Suncor Energy

The Fort Hills project has received approval for a first phase of 160,000Mbls/d. Suncor, the operator of the project, said that the oil sands mine has to be found economical before it will sign off on a final investment decision on the joint venture with French oil giant Total (NYSE:TOT). Total owns 39.2% of the project while Suncor owns 40.8%, and Teck Resources (NYSE:TCK) owning the remaining 20%.

According to the company's Chief Financial Officer Bart Demosky, the price differential between bitumen and West Texas crude is a hurdle and it will continue to be until it becomes easier to move the product, he said. The Fort Hills mining project is focused on design engineering, site preparation and early activity related to long-lead items to progress the project towards a sanctioning decision expected in the latter half of 2013.

Joslyn North Mining Project

Source: Total E&P

Located North of Fort McMurray, the Joslyn North mining project is a joint venture between Suncor at 36.75% interests, Total E&P at 38.25% and is the project operator, Inpex Canada Limited (OTC:IPXHF) at 10% and Occidental Petroleum (NYSE:OXY) with the remaining 15%. The project has been approved for Phase 1 with an initial capacity of 100,000Bls/d and the start-up is expected for 2018.

Voyageur South Project

Suncor considers Voyageur South to be a "longer-term" project and has not confirmed a start-up date. The company has planned a phase 1 with an estimated initial capacity of 120,000Bls/d.

Chard Project

The Chard project, located approximately 62 miles South of Fort McMurray, was announced last year and the company estimated its phase 1 to be about 40,000Bls/d. No timeline has been announced for a possible regulatory approval.

Meadow Creek Project

Meadow Creek is located South of Fort McMurray and is a joint venture in which Suncor is the operator and owns 75% interests while CNOOC (NYSE:CEO) owns the remaining 25%. The project has been approved for 2 phases of 40,000Bls/d.

Lewis Project

Lewis is located North of Fort McMurray and the company has not determined the time in which it plans to develop this asset. Suncor has planned two phases for a production of 40,000Bls/d each.

Core Financials

The producer recorded strong Q1 2013 operating earnings of $1.37 billion or $0.90 per common share, compared to $1.32 billion or $0.84 per common share for Q1 of 2012. Oil sands operations contributed $411 million in operating earnings for the same period from $540 million in Q1 of 2012. The decrease in operating earnings for the oil sands operations was due primarily to lower price realizations and higher DD&A, partially offset by higher production volumes and lower royalty expenses.

Source: Suncor's Q1 2013 Earnings Release

Cash flow from operations was $2.28 billion for Q1 of 2013, compared to $2.42 for Q1 of 2012. Cash flow from operations for the oil sands segment in Q1 of 2013 was $848 million compared to $1.12 billion in Q1 of 2012. In addition to the same factors affecting operating earnings, cash flow from operations in Q1 of 2013 was impacted by a $93 million charge as a result of not proceeding with the Voyageur upgrader project.

In red: Operating earnings

In yellow: Cash flow from operations

Source: Suncor's Investor Information, May 2013

In addition to this charge, Suncor also acquired Total E&P Canada's share of costs as a result of not proceeding with the project of $90 million, for expected total cash spend of $183 million. As a result, Suncor gained full control over the partnership assets, including a hot bitumen blending facility and tankage, which will provide added logistic flexibility and storage capacity to support the company's growing oil sands operations and the midstream component of the company's integrated business model.

Cash operating costs for oil sands operations increased slightly to $1.12 billion in Q1 of 2013 from $1.06 billion in Q1 of 2012. Cash operating costs were higher due to incremental costs associated with higher production from its Firebag asset, larger operations from recently commissioned assets, higher energy prices in Q1 of 2013, and higher unplanned maintenance primarily in mining and extraction, partially offset by the net benefit of increased power sales. On a per barrel basis, cash operating costs for oil sands operations decreased in Q1 of 2013, averaging $34.80/Bbl compared to $38.10/Bbl in Q1 of 2012 due to higher production volumes.

Sales volumes for oil sands operations increased to 359,400Bls/d in Q1 of 2013 from 332,800Bls/d achieved in Q1 of 2012, reflecting the overall increase in production volumes. SCO sales mix was impacted by unplanned maintenance of a diesel hydrotreater, which resulted in lower diesel volumes in Q1 of 2013. Issues with the diesel hydrotreater were resolved late in the quarter. Sweet SCO sales were further impacted by a build of sweet SCO inventory in preparation for the planned maintenance and turnaround activities at Upgrader 1.

Average price realizations for sales from oil sands operations decreased to $78.41/Bbl in Q1 of 2013 from $90.95/Bbl in Q1 of 2012, due to lower WTI, unfavourable light/heavy differentials and higher bitumen sales volumes. Average price realizations for sweet SCO decreased due primarily to lower WTI, slightly offset by a premium for sweet SCO relative to WTI of approximately $1/Bbl compared to a discount of approximately $3/Bbl in Q1 of 2012.

(click to enlarge)

Source: Suncor's Investor Information, May 2013

Average price realizations for sour SCO also decreased in the quarter due to lower WTI, partially offset by higher demand for the product. Average price realizations for bitumen declined significantly over the prior year quarter reflecting the widening discount of WCS (Western Canadian Select) relative to WTI due to lower demand for bitumen and limited takeaway capacity.

Royalties for the oil sands segment were lower in Q1 of 2013 than for Q1 of 2012. The decrease was mainly due to lower benchmark prices for WCS that influenced the company's regulated bitumen valuation methodology used to determine royalties for mining properties, offset by higher production and lower allowable capital projects in Q1 of 2013.

The ROCE, excluding major projects in progress, for the twelve months ended March 31, 2013 was 7.1%, compared to 14.7% from year-over-year of 2012. The ROCE was impacted by approximately 4% due to an after-tax impairment charge of $1.49 billion relating to the Voyageur upgrader project in Q4 of 2012, in addition to the $127 million charge recorded in Q1 of 2013.

Source: Suncor's Q1 2013 Earnings Release

On April 15, 2013, Suncor announced that it had reached an agreement to sell a significant portion of its natural gas business in Western Canada for $1 billion, subject to closing adjustments on an economic basis, with an effective date of January 1, 2013. The transaction is expected to close during Q3 of 2013 and is subject to closing conditions and regulatory approvals.

According to Q1 of 2013, property, plant and equipment and exploration expenditures were $1.389 billion (excluding capitalized interest). Activity in the quarter included the following. Oil sands base capital and exploration expenditures were $283 million in the quarter, of which $265 million and $18 million were directed towards sustaining and growth activities, respectively.

Capital expenditures were primarily focused on reliability and sustainment of the existing Oil Sands Base assets, including the construction of assets to support the ongoing TRO process, activities aimed at reducing fresh water use, including the construction of a water treatment construction of plant and initial expenditures pertaining to the planned maintenance and turnaround at Upgrader 1. In addition, the construction of the final two of the four storage tanks in Hardisty, Alberta was almost complete by the end of the quarter with commissioning anticipated for Q2 of 2013.

Source: Suncor's Investor Information, May 2013

In-situ capital and exploration expenditures were $331 million, of which $88 million was directed towards growth projects. Minor construction activities for Firebag Stage 4 continued for the diluent stripping unit and the insulated pipeline that will transport bitumen without requiring additional diluent between Firebag and Suncor's Athabasca terminal. These assets are expected to be commissioned in Q2 of 2013. Pipeline infrastructure and additional tankage at Suncor's Athabasca terminal to facilitate increased bitumen volumes from Firebag is currently being installed and expected to result in an additional capital lease in Q2 of 2013. The following chart illustrates Suncor's capex spent quarterly.

SU Capital Expenditures Quarterly Chart

Growth capital also includes expenditures related to the winter drilling program and the execution of a de-bottlenecking project at the MacKay River facilities that is intended to increase production capacity in the second half of 2014 and ultimately result in total capacity of 38,000Bls/d by 2015. Sustaining capital expenditures of $243 million were directed primarily towards the design and construction of new well pads that are expected to maintain existing production levels in future years and infill drilling programs at Firebag that are expected to optimize the level of production obtained from the associated reservoirs.

Oil sands ventures growth capital expenditures were $261 million. Suncor continues to work closely with co-owners on progressing the Fort Hills and Joslyn mining projects. The Fort Hills mining project is focused on design engineering, site preparation and early activity relating to long-lead items to progress the project towards a sanctioning decision in the latter half of 2013. The company continues to focus on design engineering and site preparation of the Joslyn mining area and plans to provide an update on the targeted timing for a sanction decision on the project when available.

Source: Suncor's Investor Information, May 2013

Suncor's capital resources consist primarily of cash flow from operations, cash and cash equivalents, and available lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2013 capital spending program of $7.3 billion and meet current and long-term working capital requirements through existing cash balances and short-term investments, cash flow from operations and available committed credit facilities.

Cash and cash equivalents increased to $4.52 billion at the end of Q1 2013 from $4.39 billion in the end of 2012, due primarily to strong cash flow from operations that exceeded capital expenditures, partially offset by the acquisition of Total E&P's interest acquired for $515 million and the repurchase of $405 million of common shares.

SU Cash and Equivalents Chart

For the twelve months ended March 31, 2013, the company's net debt to cash flow from operations was 0.7 times, which met management's target of less than 2 times.

On March 31, 2013, Suncor's long-term debt totaled $10.08 billion, compared to $9.94 billion at December 31, 2012. The long-term debt to equity ratio of the company is at a healthy level with 25.33, compared to its industry's average of 66.31.

Suncor continued to return cash to shareholders through dividends per common share of $0.13 and share repurchases of $405 million in Q1 of 2013. Aligned with the company's strategic objectives and the strength of its business model to deliver consistent and improving financial results, subsequent to the quarter, Suncor approved a 54% increase to the company's quarterly dividend to $0.20 per common share beginning in Q2 of 2013.

Source: Suncor's Investor Information, May 2013

The company also received regulatory approval to purchase for cancellation up to an additional $2 billion worth of its common shares, commencing May 2, 2013 and ending September 19, 2013.

Suncor has proved and probable reserves of 6.9 billion barrels and 23.5 billion barrels of contingent resources. The company estimated its in-situ reserves at 12.4 billion barrels while its mining assets would hold approximately 6.7 billion barrels. Furthermore, Suncor estimated that its production outlook would exceed 34 years assuming that its 6.9 billion barrels of oil equivalent of proved and probable reserves are produced at a rate of 549,100/Boe per day, the 2012 production rate of the company.

Source: Suncor's Investor Information, May 2013

Bottom Line

The upstream of Suncor accounts for 70% of cash flow, producing 550Mboe/d (65% oil sands), 92% weighted to oil. Production is projected to grow to 689Mboe/d by 2017 assuming 5% CAGR (compound annual growth rate), accounting for 80% of cash flow. Relative to its peers, the in-situ assets of Firebag and MacKay River are high-quality as measured by porosity, permeability, and pay thickness.

Suncor's dividend yields 2.61%, a sustainable payout ratio. Notably, the company undertook a $2.5 billion of shares repurchased since September 2011, representing approximately 5% of the shares outstanding. Moreover, an additional $2 billion share buyback was authorized in April 2013.

Therefore, the company has significant upsides that set it apart from most of its competitors in the Canadian oil sands:

  1. Strong balance sheet
  2. Productive and substantial cash flow generation from its mining assets
  3. Strong position in the oil sands provides low-risk and an economical source of oil
  4. Several promising projects in the pipeline
  5. Integrating its downstream business with oil sands production provides more valuation for each barrel of bitumen
  6. One of the largest reserves in the area
  7. Cash operating costs are trending below $35/Bbl
Source: Carbonate Triangle's Athabasca Investment Guide: Suncor Energy Edition - Part 2