New York Times columnist, Princeton professor, scourge of the right and hero of the left Paul Krugman made a plain-vanilla economic observation yesterday on the new dynamics of the oil market (although he couldn’t avoid a political segue):

One of the curious things about economic debate in the later Bush years was the conviction among many on the right that there wasn’t a bubble in housing, but that there was one in oil.

We now know the truth about housing. But what about oil?

Oil prices did spike to triple-digit levels in early 2008, then drop sharply. But think about the fact that right now, with the world economy still seriously depressed, oil is at $80 a barrel. This suggests to me that high oil prices are largely caused by fundamentals.

And it also suggests that resource constraints will be an issue if and when we do get a full recovery.

In other news, the Financial Times reports that China has surpassed the US as the largest customer for Saudi oil:

Saudi Arabia’s oil exports to the US last year sank below 1m barrels a day for the first time in two decades just as China’s purchases climbed above that level, highlighting a shift in the geopolitics of oil from west to east.

The drop in US demand for oil from the kingdom, traditionally one of its primary sources, is the result of lower energy consumption overall but also greater reliance on imports from Canada and Africa.

China’s buoyant economic growth, meanwhile, is prompting Beijing to buy more Saudi oil, a trend Riyadh has encouraged through refinery joint ventures.

That the decline in US demand for Saudi oil is a result of the recent historic recession is indisputable. But Canada–home to one of the largest concentrations of energy resources in the world–means the US can make permanent this reduction of reliance on oil exporters inconveniently located in hostile regions.

The Canadian oil sands–at 172 billion barrels second only to Saudi Arabia in terms of estimated reserves–are of increasing strategic importance. No other industrial democracy in the world has an asset similar to the sands, and there certainly is no asset similar to it in the US. The “resource constraints” Krugman alludes to–which really are about new demand from China, in particular, and India–will be far easier to navigate if we take an open-minded approach to the oil sands.

As we noted in the Feb. 2, 2010, MLM:

The oil sands are fixed in the North American energy supply equation. It’s the source of 1.2 million barrels of crude per day, most of which is exported to the US. Extracting and processing bitumen from the sands is an energy-intensive process that requires both electricity and steam, which are usually generated by burning fossil fuels.

This energy intensity and related emissions–as well as the massive and ugly footprint oil sands operations leave on the natural landscape–have raised concerns about the management of the resource at the activist level, of course, but also now at the official level.

Oil sands development involves a complex set of constraints related to resource access, infrastructure requirements and, of course, environmental impact. The Athabasca region has become a flashpoint for North American debate about the future of climate change legislation.

In an ideal world North America will wake up 10 years hence to a clean-energy paradise established by hard-working Yanks and Canucks and exported around the globe in a manner that raised living standards on both sides of the border.

Something like that could happen, but it will require oil sands product to be burned before it comes about. One of the keys for US and Canadian policymakers when climate-change legislation finally is taken up is the impact of specific industries and practices on total greenhouse gas (GHG) emissions. Making the right changes in the policy and regulatory framework requires an understanding of facts.

An interesting challenge to the common perception of the oil sands is raised by a June 2009 study by engineering firm Jacobs Consultancy, “Life Cycle Assessment Comparison for North American and Imported Crudes.” According to the study, life cycle GHG emissions for oil sands are comparable to domestic and imported conventional crude oils. Furthermore, about 75 percent of GHG emissions occur during fuel consumption and aren’t impacted by the source of the crude oil.

The variance in the amount of GHG emissions generated in different types of oil production depends on how much energy is required to produce and process the oil. Some oil is just pumped out of reservoirs. Other reservoirs need injections of water or steam to retrieve the oil. Light oil requires less energy than heavy oil to be refined into transportation fuels. The amount of natural gas contained in the oil that may be flared or vented also contributes to overall GHG emissions.

GHG emissions are also generated when transportation fuels are consumed in vehicles; this accounts for about 75 percent of all GHG emissions. Total GHG emissions from production to consumption are referred to as “life cycle GHG emissions.”

The primary source of GHG emissions in oil sands mining is the energy required to mine and transport the oil sand, separate the oil from the sand, and process the oil. For in situ operations, the primary source of GHG emissions is the combustion of natural gas to generate steam. The oil sands industry has, through continual advancements in technology and energy efficiency, reduced GHG emissions per barrel by more than 30 percent since 1990. Cogeneration further reduces GHG emissions, and additional reductions are expected through the development of carbon capture and storage (CCS) and new in situ extraction technologies.

Cogeneration produces steam and electricity from a single source, and because cogeneration plants are sized according to a facility’s steam requirements there’s often more electricity produced than required.

The excess electricity is sold to the grid, meaning less natural gas and coal needs to be used to meet electricity needs. This significantly reduces GHG and other air emissions. All existing oil sands mines and all but a few small in situ projects have cogeneration facilities (over 98 percent of oil sands production has associated cogeneration). Cogeneration in the oil sands provides approximately 18 percent of Alberta’s total electricity supply.

CCS is well understood from a technical perspective but widespread implementation is limited by challenging economics and a lack of infrastructure. The Alberta government has committed CAD2 billion to CCS development, the federal government has committed CAD1 billion, and industry is also investing heavily.

As the required infrastructure is developed, CCS has the potential to significantly reduce GHG emissions from the oil sands. It’s likely that initially CCS will be applied to coal-fired electricity facilities because of their larger, more concentrated sources of carbon dioxide.

In situ operations require significant amounts of energy to generate the steam that’s injected underground to warm the bitumen before it can be pumped to the surface. Significant progress has been made in reducing the amount of steam required to achieve this, and several technologies could further reduce GHG emissions per barrel to levels equivalent to–or better than–imported conventional oil.

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The Roundup

Two more CE Portfolio recommendations added their names to the roster of companies reporting solid results for the fourth quarter and 2009, Conservative Holding Keyera Facilities Income Fund (TSX: KEY-U, OTC: KEYUF) and Aggressive Holding Penn West Energy Trust (TSX: PWT-U, NYSE: PWE).

Keyera reiterated a commitment to convert to a corporation without cutting its monthly payout, and, though it trimmed its sails a bit, Penn West will back a plan to shift from gathering assets to exploiting them with an ambitious capital budget for 2010.

Here are the highlights.

Conservative Holdings

Keyera Facilities Income Fund (TSX: KEY-U, OTC: KEYUF) reported solid results from both of its operating units. Overall distributable cash flow (DCF) was CAD260 million (CAD4.08 per unit), up 92 percent from CAD136 million (CAD2.20 per unit) in 2008. Hedging gains added CAD51 million (CAD0.80 per unit) to DCF. Keyera distributed CAD144 million (CAD2.25 per unit) to unitholders, for a payout ratio of 55 percent.

Cash flow from operations was CAD313.2 million, up CAD222 million, or 243 percent, from 2008. Fourth-quarter DCF was CAD43 million (CAD0.66 per unit), up 20 percent from the year-ago period.

Unitholders will vote on May 11, 2010, on a management proposal for Keyera to become a corporation. Assuming a favorable outcome, Keyera will complete the conversion will become effective Jan. 1, 2011. President and CEO Jim Bertram reiterated a forecast Keyera already made: “We believe we are positioned to set our corporate dividends at the same level as our current annual distribution of CAD1.80 per unit, and currently anticipate continuing to make this payment monthly.”

Keyera’s Gathering & Processing unit added CAD124.4 million to DCF, a 14 percent increase from 2008. As for the Liquids Business unit, NGL Infrastructure contributed CAD58.9 million, an 18 percent increase from 2008, while Marketing generated CAD83.5 million, 18 percent lower than 2008’s record-setting total. Both G&P and Liquids set new DCF contribution records in 2009.

Looking ahead, management noted during a conference call to discuss fourth-quarter and full-year 2009 results that Keyera has been approached “by a number of producers seeking gathering and processing services. This renewed interest, coupled with increased well license activity, and announcements by several producers of increased drilling budgets, are positive signs for increased drilling activity in 2010.” A lot of this new activity has been catalyzed by horizontal drilling.

Keyera set itself up for future growth in November 2009 by finalizing an agreement to provide transportation, storage and terminaling services to Imperial Oil’s (TSX: IMO, NYSE: IMO) Kearl oil sands project. The long-term, fee-for-service agreement is an excellent template for future tie-ups with other oil sands operators. It will start to add to Keyera’s cash flow in 2012, and it establishes Keyera as the top diluent-services providers in the key Edmonton-Fort Saskatchewan area. Keyera Facilities Income Fund is a buy up to USD24.

• AltaGas Income Trust (TSX: ALA-U, OTC: ATGFF)–February 26 (confirmed)
• Artis REIT (TSX: AX-U, OTC: ARESF)–March 16 (confirmed)
• Atlantic Power Corp (TSX: ATP, OTC: ATLIF)–March 29 (confirmed)
• Bird Construction Income Fund (TSX: BDT-U, OTC: BIRDF)–March 19
• Canadian Apartment Properties REIT (TSX: CAR-U, OTC: CDPYF)–February 24 (confirmed)
• CML Healthcare Income Fund (TSX: CLC-U, OTC: CMHIF)–March 4
• Colabor Group (TSX: GCL, OTC: COLFF)–February 25
• Davis + Henderson Income Fund (TSX: DHF-U, OTC: DHIFF)–March 2 (confirmed)
• IBI Income Fund (TSX: IBG-U, OTC: IBIBF)–March 17
• Innergex Power Income Fund (TSX: IEF-U, OTC: INRGF)–March 16
• Macquarie Power & Infrastructure Income Fund (TSX: MPT-U, OTC: MCQPF)–March 2 (confirmed)
• Northern Property REIT (TSX: NPR-U, OTC: NPRUF)–March 17 (confirmed)
• Pembina Pipeline Income Fund (TSX: PIF-U, OTC: PMBIF)–March 3
• TransForce (TSX: TFI, OTF: TFIFF)–February 25 (confirmed)

Aggressive Holdings

Penn West Energy Trust’s (TSX: PWT-U, NYSE: PWE) 2009 average production of 177,000 barrels of oil equivalent per day (boe/d) beat a projection of 171,500 to 176,500 boe per day, and the company also announced an aggressive though slightly scaled back spending plan for 2010.

Penn West will spend more on capital development in 2010, CAD700 million to CAD850 million, up from an actual figure of CAD688 million in 2009. (Management guided with a range of CAD650 million to CAD700 million in capital expenditures for 2009.) In December the company forecast 2010 spending of between CAD750 million and CAD900 million.

President and Chief Operating Officer Murray Nunns is bullish on drilling trends at three critical Penn West projects, however, and took pains to note during a conference call to discuss results that the company “will expand to a level commensurate to the growth potential of our assets.” Reserve growth is tied to horizontal drilling in Penn West’s three core areas, which include the prodigious Pembina play.

Funds flow from operations (FFO) was CAD366 million (CAD0.86 per unit) in the fourth quarter, down from CAD490 million (CAD1.26 per unit) in the fourth quarter of 2008. Revenue fell 14 percent to CAD831 million from CAD968 million.

West Texas intermediate crude averaged USD76 per barrel during the period, up 29 percent from an average of USD58 a year ago. Natural gas averaged CAD4.39 per million cubic feet (mcf), a 23 percent decline from CAD7.03 a year ago. For the fourth quarter, production fell 8 percent to 170,164 boe/d.

Management reduced net debt by approximately CAD822 million during 2009, and last month a swap of assets with Crescent Point Energy (TSX: CPG, OTC: CSCTF) left Penn West with CAD434 million more to apply to debt reduction. Total debt is now CAD3 billion. Nunns highlighted the way Penn West has de-leveraged by CAD1.3 billion during the past 18 months–during “one of the toughest downturns the economy has seen in recent memory, or extended memory.” The goal of all this debt-shedding was not only to protect the balance sheet amid uncertainty; it was to position the company to pay a competitive yield and at the same time offer compelling growth prospects once it converted to a corporation. Penn West’s debt-to-EBITDA as of Dec. 31, 2009, was 1.85 times; management would like to see this ration in the 1.5-to-1.7 range.

In an additional step taken to prepare for the eventual transition from trust to corporation Penn West has established an exploration team that will find new opportunities to grow the reserve base. This, as management noted during the conference call, is an essential step for a company that’s reorienting toward growth. Nunns went so far as to say, “We believe we will be in position by later this year to be drilling plus or minus five to 700 wells a year…that’s what we see as a requirement for [the] future.”

For 2010 management has locked in 35 percent of its liquids production at an average price of CAD75 per barrel, with a floor of CAD60. Approximately 20 percent of natural gas production is hedged, at an average price of CAD6.34 per million cubic feet (mcf).

Management and the board of directors have settled on a CAD0.15 per unit per month distribution through the end of May, at which time they’ll meet to reevaluate. Management noted that it will convert within the next 10 to 16 months, either at the end of 2010 or early in 2011. Like other trusts, it wants to enjoy its tax advantage for as long as possible.

For purposes of estimating a future dividend from a converted Penn West it’s important to note that the company added productive resources in recent years then worked to clean up its balance sheet. Management is of the mind that the current resource base would support the current payout level–but also wants to add a “growth component” to the story. Much will depend on costs and how efficiently existing assets can be exploited; more important, however, will be the prices of oil and natural gas. Penn West Energy Trust, laying a strong foundation for an attractive combination of yield and growth, is a buy up to USD20.

• Ag Growth International (TSX: AG-U, OTC: AGGZF)–March 11 (confirmed)
• Chemtrade Logistics Income Fund (TSX: CHE-U, OTC: CGIFF)–February 24 (confirmed)
• Daylight Resources Trust (TSX: DAY-U, OTC: DAYYF)–March 2 (confirmed)
• Enerplus Resources Fund (TSX: ERF-U, NYSE: ERF)–February 25 (confirmed)
• Newalta (TSX: NAL, OTC: NWLTF)–March 5
• Paramount Energy Trust (TSX: PMT-U, OTC: PMGYF)–March 10
• Peyto Energy Trust (TSX: PEY-U, OTC: PEYUF)–March 10 (confirmed)
• Provident Energy Trust (TSX: PVE-U, NYSE: PVX)–March 11 (confirmed)
• Trinidad Drilling (TSX: TDG, OTC: TDGCF)–March 3 (confirmed)
• Vermilion Energy Trust (TSX: VET-U, OTC: VETMF)–March 26