Valuation

Land sale spending in Alberta surged in 2010 due to a combination of new plays, enhanced oil sands technologies and a rebound in oil prices. From April 2010 to March 2011, 365,969 hectares of Crown oil sands leases were sold, totaling $54.927 million in land sale revenue with an average price of $150.09 per hectare. This average price is up from $133.42 per hectare for the same period in 2009/2010. An annual summary of oil sands public offerings is provided in the table below:[1]

Table 3 - Summary of Oil Sands Public Offerings - By Fiscal Year (April to March) - Leases and Permits

Acquisition Structures

The vast majority of multi-party oil sands projects are structured as joint ventures or partnerships. Preference for a particular structure is most often based on income tax planning, with commercial objectives being another major consideration.

Acquisitions are generally made by purchasing a participating interest in a joint venture or an interest in a partnership. The operating agreements that come into effect upon closing of an acquisition are often the subject of detailed negotiation and discussion, since these documents set out the ongoing development and governance of the project through its life-cycle.

Regulatory Approvals

An oil sands investment, regardless of whether the target is a bitumen extraction project, an upgrader, a transportation project or a derivative play, may be subject to Canadian regulatory approvals, two of the most common being:

1. The Investment Canada Act (ICA), which governs the acquisition of control of a Canadian business whose total asset book value exceeds $330 million (adjusted annually for inflation). Acquisitions by state-owned foreign enterprises are subject to additional specific guidelines. Investments can also be subject to a national security review.[2] State-owned investors should expect to be required to file information to address the following issues:
   • their standards and transparency of corporate governance and public disclosure;
   • the role of their board of directors;
   • the presence and role of independent directors;
   • the mechanisms available to the state to influence the business decisions of the enterprise; and
   • any other matters that might be relevant to determining whether and to what extent the enterprise is likely to be run on a commercial basis.

Amendments to change the financial threshold and its method of calculation have been introduced.

2. The Competition Act, which applies to an acquisition of control where the book value of the project’s or entity’s assets (or its annual Canadian sales) exceed $73 million (adjusted annually for inflation) and the asset book value or annual Canadian sales of the parties to the transaction and their affiliates exceed $400 million.

Financing a Project

Generally, large existing producers deemed to be investment-grade risks have had little trouble securing financing for oil sands development. For example, the credit facilities in respect of the CNRL Horizon Project, the Nexen-Opti Long Lake Project and the Total Joslyn Project are standard facilities funded by conventional Canadian banking syndicates.

Project debt financing raises several issues within the framework of a joint venture or partnership. Depending on the partners’ positions, some may have a greater desire for external financing than others. This will become an issue when granting security, as the cooperation of all partners will be required. Matters can be further complicated if the project has a combination of partners with high and low credit ratings. One possible structure is for the partners who have no need for project financing to lend into the partnership at the same rate as the less creditworthy partners, to maintain economic consistency.

The lingering effects of the global economic downturn have had an impact on the availability of debt financing in relation to oil sands projects. This has led some companies active in the oil sands to finance projects through public offerings. Bennett Jones’ Capital Markets Group has significant experience and expertise in assisting clients with such financing.

Alberta’s Royalty Framework

General Royalty Framework

In response to Albertans’ desire to receive a larger share from the development of Alberta’s non-renewable energy resources, the provincial government released The New Royalty Framework on October 25, 2007, and the changes went into effect on January 1, 2009. However, the Alberta government recently pulled back from The New Royalty Framework in the upstream natural gas and conventional oil sectors with the announcement of the Alberta Competitiveness Review changes on March 11, 2010. Citing several factors, including structural market changes, advancements in technology and regulatory barriers, the Alberta Competitiveness Review concluded that Alberta had lost competitiveness relative to other competing jurisdictions in Western Canada and the United States. To address this, several changes were implemented, including decreasing the maximum royalty rates on natural gas and conventional oil. A world oil price sensitive sliding scale has been implemented for oil sands royalty rates ranging from one to nine percent of gross revenue in pre-payout and 25 to 40 percent of net revenue in post-payout.

In mid-2010, the Alberta government unveiled its Emerging Resources and Technologies Initiative, which modified the royalty rate for wells that require use of high-cost technologies. This strengthens a producer’s ability to invest in additional wells, as well as research and development. The government expects that stimulating application of new technologies in resources that have not been tapped will increase overall production, resulting in increased economic activity and secure long-term royalty revenue from new resource discoveries. The Emerging Resource and Technologies Initiative will be reviewed in 2014 and the Alberta government has committed to providing three years notice to industry at that time if it decides to discontinue the initiative.

The following provides a summary of oil sands royalty revenue collected by the government of Alberta from 2006 to 2011:

• 2006/07 - $2.411 billion
• 2007/08 - $2.913 billion
• 2008/09 - $2.973 billion
• 2009/10 - $3.160 billion
• 2010/11 - $3.723 billion

The BRIK Program

Alberta’s BRIK program is a key component of the province’s royalty regime. As the resource owner, the province is entitled to take its royalty share of bitumen production in kind. The decision to exercise the in-kind option for bitumen was identified in October 2007 as a way for the Crown to use its share of bitumen strategically to supply potential upgraders and refineries in Alberta, and to optimize its royalty share by marketing those volumes. A Request for Proposals to purchase or process 75,000 bbl/d of Crown-owned bitumen was issued in July 2009 and negotiations began in May 2010. As previously described, the NWU/CNRL Refinery project and the Alberta Carbon Trunk Line project are the first beneficiaries of the BRIK Program.

The guiding principles for the BRIK program are as follows:

1. The royalty regime will continue to be based on a revenue minus cost scheme.
2. Any changes to royalty systems and obligations will be open and transparent.
3. The BRIK framework will encourage a fair, efficient and openly competitive market.
4. The BRIK market design must provide confidence to investors and customers and be supported by a clear and stable regulatory framework.
5. The BRIK market design should minimize the potential exercise of undue market power and unwarranted transfer of wealth.
6. Where operators are regulated to perform BRIK business functions, they will be compensated appropriately.
7. BRIK program design will seek to minimize costs to both industry and the Crown.
8. BRIK business rules will take operational constraints into consideration.
9. BRIK market design will respect the business investments that have been made in Alberta.
10. The BRIK market design will encourage more value added products based on bitumen in Alberta.

The government of Alberta expects that the BRIK program will stimulate value-added activities (such as upgrading, refining and petrochemical development) and, by assuming some risk and cost associated with processing, enable Alberta to obtain increased revenue compared with taking cash based on bitumen pricing.