The Energy Report: Technology is changing the exploration landscape. It has enabled companies to reach untapped oil and gas in what were previously considered non-economical parts of many conventional producing reservoirs and to enter into many unconventional shale plays. How is this changing the game for North American exploration and production (E&P) companies?
Kevin Shaw: What's old is new in terms of those existing pools, especially in the Western Canadian Basin. It's all about going into poor-quality rock, which over the last 30 years typically would have been uneconomic to drill vertically. Horizontal drilling can open up more reservoir rock, connect the wellbore to more reservoirs, go into tighter sands with multistage fracture completions and increase recovery factors to increase reserves and production within the Western Canadian Basin. With multistage fracs, what was old once is now new, and it's really revitalized the industry.
The use of horizontals started largely in the southeast Saskatchewan Bakken play, which translated down to North Dakota, and also moved into the U.S. shale plays (Marcellus, Eagle Ford, etc.) and the Canadian Montney formations on the gas side. Now horizontal multistage fracs are being utilized in a big way in both the Cardium and the Viking oil resource plays.
The Beaverhill Lake is another zone coming into play, and there are several other zones of interest. In the Cardium, for example, they're now extending lateral lengths of horizontals, putting in more fracs and getting better production and well results month-to-month out of the gate, as well as getting more reserves booked to each well they drill. This has changed rapidly over the last 12 months.
So it's game on in a big way for technology; it's game on for many of the older pools that had been considered depleted. And it's an evolving space, with a lot of technology that keeps changing all the time. Companies are even starting to use horizontal frac technology with conventional pools to increase recovery factors and production reserves.
The game has changed in a big way over the last few years. It's great for service companies as well as E&Ps. Well by well, pool by pool, production rates are being enhanced in most new plays.
TER: Competition for drilling-related services drove costs up about 16% in 2010, and costs are expected to continue rising at least through the first half of 2011. How is this affecting these companies?
KS: As you say, the market for drilling rigs is tighter, but the big bottleneck is fracing, due to the boom in the application of the technology. A lot of the frac systems and fracing units need a lot of equipment and a lot of horsepower for big multistage fracs. The competition for that is intense, with waiting lists on both sides of the border in most key plays. That definitely gives the service companies pricing power. In fact, service costs are likely to continue to trend higher, which will lower netbacks unless oil prices continue to rise alongside increased development costs.
TER: So are you looking at companies with higher margins to compensate for rising costs?
KS: I like to look for companies that can put drilling programs together for an "assembly-line" approach to drilling horizontals in relatively close proximity to one another. These companies would have large acreage positions concentrated in the right neighborhoods. Bellatrix Exploration Ltd. (TSX:BXE), for example, which is an emerging mid-cap producer in and around 10,000 to 11,000 barrels of oil equivalent (BOE)-per-day, has a dominant position in the Cardium oil fairway.
It's been hugely successful over the last year-plus with a focused effort on both the Cardium and the Notikewin resource plays. Its acreage is such that it has about six rigs running currently—four operated and two non-operated—and Bellatrix is able to repeat by drilling horizontal after horizontal from a combination of pads, or close proximity rig moves.
Even with increasing service company prices, Bellatrix is able to lower costs by being more efficient at shorter rig moves, building efficiencies into facilities or pipeline infrastructure and being strategic in planning its program. Not all companies can do this because they don't necessarily have large acreage blocks in the areas where they need to be drilling. Bellatrix is definitely one that can do that and is expected to continue to perform well throughout 2011.
TER: As of early January, you had a target price of $6.50 on Bellatrix.
KS: We have a $7.50 target and a Strong Buy rating, with Bellatrix a continued 2011 "Domestic E&P" top pick.
TER: Is that based on oil prices?
KS: Our recent target shift upwards was based on Bellatrix's latest reserves report. We were modeling proven and probable (2P) reserves of 31 million BOE. They hit 40 million-plus BOE, definitely driven by the Cardium and the Notikewin Zone horizontal development plays. Bellatrix posted great results, one of the best domestic energy companies in the business today in terms of investing in both the near and long term, and arguably in two of the hottest plays in western Canada. As the company continues to invest capital into horizontal "manufacturing" in the Cardium and Notikewin, there is solid upside year over year.
TER: Any others?
KS: SkyWest Energy Corp. (TSX.V:SKW) is a pure-play Cardium small cap, 100% focused in the Cardium, and it hit an exit rate of 2,000 BOE-per-day last December. This company has been around only for a short time, inside a year.
TER: Not bad production for a start-up.
KS: It's ramped up very quickly. Starting at around 350 BOE-per-day, it's built its Cardium acreage from about 11 to 40-plus net sections. SkyWest is drilling with one rig, horizontal after horizontal, and has been successful out of the gate. It's in one of the sweet spots in the play, alongside Bellatrix and others in the Williston Green and South Pembina areas. It's definitely one of the top-performing areas in the Cardium, with wells that have anywhere between 300 to 3,000 BOE-per-day in terms of initial production rates.
The nice thing about SkyWest's valuation is that it's reasonably priced on a flowing BOE and in my opinion, continues to be a favorable "takeout" candidate in the near term. Depending on the timing, with every well they drill, they get more expensive to take out. In the meantime, it's a nice pure play call if you want exposure to the Cardium.
TER: In addition to all of the action in Canada, one of your research reports compared Argentina favorably with Colombia and stated that Argentina could be the next hot market for oil and gas. Can you tell us about that?
KS: Yes. Argentina is one of the next potential hot beds on the international circuit right now, sitting on a huge untapped conventional reservoirs and massive upside potential in unconventional shale plays for both gas and oil. It's really largely been underexploited, and the large companies—the majors around the world—have not really gone after them as of yet until now.
Historically, foreign direct investment in Argentina had been suppressed by government-controlled pricing caps in a lot of the gas production agreements. Of late, a couple of noteworthy things are happening on the macro side in Argentina, which is a net importer of gas. In the last several years, Argentina has sold gas domestically anywhere from $0.50 to $2 per million cubic feet (MCF), yet paying about $9 per MCF to import LNG from places like Bolivia. It's an unsustainable situation.
And Argentina controlled oil pricing, too. Those controls have been easing, and we're now seeing some higher realized sale prices on oil of $52/barrel and more. In addition, the government now gives exporters that are currently in the country an incentive tax credit that tacks another $5 to $11/barrel on top of those prices. So netbacks on Argentina's oil are now on par with the average in Canada. Some of the other operating costs in the country are low, and royalties are also low compared to other countries.
A lot of positive things are happening in Argentina. For example, they used to sell all their gas at around $2 per MCF. They have now approved contracts for unconventional and tight gas plays to go to $5 and $6 and more per MCF, which is huge. As a net importer, they have a situation they're trying to address; they have to spark more foreign direct investment, which also involves encouraging companies that are already in-country to ramp up activities. It's a win-win for Argentina, for the government and for the operators.
TER: What are some companies with favorable gas and oil exploration blocks there?
KS: Over the last three or four months, Apache Corporation (NYSE:APA) has ramped up activities in a big way. Repsol-YPF S.A. (OTCPK:REPYY) and Pan American Energy [privately owned] are big players in Argentina but of late, Exxon Mobil Corp. (NYSE:XOM) and Total (NYSE:TOT) have entered the space along with Petrobras (NYSE:PBR).
They're not only focusing on conventional O&G exploration and development but also heavily on the unconventional side for both gas and oil, and starting to apply horizontal multistage frac technology through Halliburton Co. (NYSE:HAL), the BJ Services Company, which is now part of Baker Hughes Inc. (NYSE:BHI), and others. Unconventional shale plays in Argentina have the potential for 200+ trillion cubic feet (TCF) on the gas side alone and are just starting to be tested with horizontal technology.
YPF, for example, announced in December a new shale gas discovery of approximately 4.5 TCF in one of the big predominant zones of interest, the Vaca Muerta Shale zone. That was just one discovery YPF has delineated and announced; many others throughout the Argentina basins could be brought to light through exploration and delineation of this widespread shale. A second potential prolific shale zone is the Molles Formation, which has huge potential like the Vaca Muerta in Argentina.
The majors are going there for a reason. They can make an awful lot of money at $5 to $6 per MCF—actually, there's more money in gas in Argentina than in North America currently.
