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Get ready for M&A

Increased M&A activity can be expected in Canada, with junior E&P companies the most likely targets, writes WJ Simpson

CANADA'S oil and gas sector is set for a period of consolidation, as companies enriched by high energy prices and hungry for stakes in emerging oil and unconventional gas plays in British Columbia and Saskatchewan attempt to grow through mergers and acquisitions (M&A).

Oil prices appear to have established a base at well over $100 a barrel and Goldman Sachs and Cameron Hanover have recently claimed that $200/b is a realistic prospect in the near future. North American gas prices, meanwhile, have recovered since the dip of 2006, trading above $11/'000 cubic feet (cf), with two-year contracts being agreed at a minimum of $9/'000 cf.

Canadian oil and gas assets are already the most actively traded in the world – 8% of properties turn over every year, compared with 5% in the US, 2-3% in the North Sea and 1% in the rest of the world.

Even through an 18-month drilling downturn, induced by uncertainty over the future of Alberta government royalties, now due to increase by an average 20% in 2009, and the prospect of tougher climate-change regulations, Canada posted a record year for M&A in 2007. Deal values amounted to C$49.8bn ($48.8bn), beating the previous high of C$46.4bn in 2001 and easily surpassing the C$29.8bn of 2006, with four transactions exceeding C$5bn, according to Sayer Energy Advisors (see Table 1).

The total was achieved despite a slide in the median price paid per flowing barrel of assets to C$48,167 per barrel of oil equivalent a day (boe/d) from C$60,418/boe/d in 2006, because of limits imposed by the government on the growth of income trusts until new tax rules take effect in 2011. In addition, overall valuations of exploration and production (E&P) companies were down from 2005 and 2006, with many trading below their net asset values, Sayer said.

Lower asset values reflected a decline in acquisitions by income trusts, which, for several years, have been the driving force of M&A in Canada, as they bought junior producers in the 10,000-20,000 boe/d range. However, since late 2006, they have been constrained by government limits on how much they could expand until new trust tax rules take effect in 2011.

Encouraging M&A

The shortage of credit, because of the US lending crisis, coupled with the inability of smaller, gas-weighted E&P companies to raise financing through equity markets are likely to encourage firms to try to grow through M&A. Sayer analyst Ryan Young expects a "high number of corporate acquisitions and mergers done on a share-for-share basis".

Adam Waterous, vice-chairman and president of divestiture and acquisition firm Scotia Waterous, is certain Canada is in the "early innings of a long bull market" for M&A that could repeat the consolidation wave of 2000, when the bulk of mid-tier, gas-focused companies – generally those producing upwards of 50,000 boe/d – were seized by US buyers.

He says targets range from junior explorers to oil-sands operators, and expects buyers to emerge from the ranks of international companies, following the lead of StatoilHydro, Total, BP and Taqa, the United Arab Emirates' energy-investment fund, which have made acquisitions in Western Canada over the past year.

Tristone Capital's offices in Calgary, Houston, Buenos Aires and London are dealing with a flood of M&A inquiries relating to Canada, according to David Vetters, managing director of the energy advisory firm. Junior companies that are unable to finance development of their resources are among the likely acquisition targets of the next six to 12 months, Vetters says. He adds that large independents are likely to shift their focus to outright take-overs of publicly traded companies, as the opportunity for selective asset purchases – which have characterised their buying strategy over the past decade – diminish.

Drawn to shale and tight gas

At the junior level – mostly involving companies producing under 20,000 boe/d – investors are being drawn to firms that have made oil and gas discoveries in the shale and tight gas plays of northeastern British Columbia and the Bakken and Shaunavon oil formations of southern Saskatchewan.

AJM Petroleum Consultants has estimated the Upper Montney play of British Columbia has gas-in-place of 50 trillion cf; it says that if only half is recoverable it would give a significant boost to the 58 trillion cf remaining in Western Canada, where 3.5bn cf/d of new volumes are needed every year to sustain output.

Share prices of companies with exposure to those potentially lucrative areas are on the rise; this year, ARC Financial's Junior Producers Equity Index has risen by 20%, compared with about 3% for the Toronto Stock Exchange's composite index.

Nova Scotia: reversing the decline

ON THE face of it, the petroleum industry in the eastern Canadian province of Nova Scotia is in a reasonable state of health. A long-delayed gasfield is finally on track to start producing by late 2010; a steep production decline at the one existing gas project has been reversed; exploration companies have been given various new incentives to invest; and plans for a C$4.6bn ($4.5bn) liquefied natural gas (LNG) terminal remain alive.

In other respects, however, the sector is at its lowest ebb in two decades – although Nova Scotia, close to the large New York and New England markets, is estimated to hold 40 trillion cubic feet (cf) of gas resources. Arriving at where it now stands has been a painful experience: no offshore discovery has been made for years, despite C$1bn spent in wildcat drilling. Most of the big oil companies have left; including ExxonMobil, Royal Dutch Shell, Chevron, Hunt Oil and StatoilHydro, which paid at least C$0.6bn to void exploration commitments. More than 100 support companies have departed.

Tacitly conceding that multinationals can no longer be enticed by the prospect of working in a lightly explored basin – only 200 wells have been drilled in 40 years compared with 50,000 in the US Gulf of Mexico – the Nova Scotia government has tried lowering the costs of admission.

"We're encouraging new people to come here," says Diana Dalton, chair of the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB). "We're saying come and explore at a minimal cost; do some preliminary work."

Offshore licences now cost as little as C$100,000, but expire in two to three years unless a qualifying well is drilled. When companies decide not to drill, the licences will revert to the government and all the data they have gathered will be publicly accessible. Previously, nine-year licences carried upfront deposits in the millions of dollars. The objective is to attract a wide range of smaller explorers, characterised by Dalton as "adventurers". She says: "It isn't always the big companies like ExxonMobil and Chevron who find oil and gas; they buy in after it is found."

In addition, Nova Scotia has opened up its bank of non-confidential well and seismic data to help prospective explorers "make informed decisions".

Positive changes

Companies such as ExxonMobil and EnCana have described the changes as "positive," without committing themselves to new exploration programmes. Whether others have been won over will be known by 30 June, the deadline in a CNSOPB call for bids for two shallow-water parcels in the Sable sub-basin, where 23 "significant" discoveries have been made.

To encourage bids, the CNSOPB has released data from one parcel – the 1972 Eagle discovery, which has estimated recoverable reserves of up to 0.72 trillion cf, but needs appraisal drilling. The board believes technological advances over recent years could raise the productivity of individual wells in that discovery to 10m-30m cf/d.

It has also released an updated geological report on the "virtually unexplored" deep-water Scotian Slope, covering 11 wells drilled from 1982 to 2004, rating the potential of the area at 12-39 trillion cf of gas and 1.3bn-4.5bn barrels of oil.

The Eagle find is within 50 km of the central processing platform for the Sable Offshore Energy Project, Nova Scotia's only producing offshore field, which has reversed a five-year decline in output to 367m cf/d in 2006 from 0.53bn cf/d in 2002; output recovered in 2007 to 440m cf/d, with the introduction of new compression facilities. And the long-delayed launch of EnCana's nearby Deep Panuke project is due on stream in 2010 at 300m cf/d, developing reserves of 632bn cf.

Despite the shelving of Anadarko's planned Bear Head LNG project in Nova Scotia, a joint venture involving Keltic Petrochemicals and Maple LNG (controlled by the US' Carlyle Group, a private-equity firm) appears to be going ahead. The partners expected to line up LNG supplies this year or next for the 1bn cf/d regasification plant, with one-third of the gas reserved for Keltic's petrochemicals complex and two-thirds for markets in the US northeast and Atlantic Canada. The plant received regulatory approval this year.

Nova Scotia is also edging into the new generation of coal-bed methane and shale-gas development. Stealth Ventures, which is seeking a buyer or partner, has signed a production agreement with the province for its Cumberland project, estimated to hold more than 1 trillion cf of in-place gas in a licence area close to the Maritimes & Northeast Pipeline that runs from Sable to New England.

Triangle Petroleum, meanwhile, is moving ahead with Nova Scotia's first shale-gas project on the Windsor Block covering 0.52m acres. Triangle director Stephen Holditch says the company is "cautiously optimistic" it has discovered a significant unconventional reservoir, with one test well flowing at 15m cf/d.


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