Natural Gas

Canada produced 5,628 billion cubic feet (Bcf) in 2009 and it exported 2,947 Bcf (net) that year. Canada is therefore the fifth-largest producer of natural gas in the world, the third-largest exporter globally and by far the largest source of foreign gas for the U.S.

Until recently, most juniors and intermediates were gas focused, with some 70% of Canadian investment in hydrocarbon development going into gas projects in 2006. As in the U.S., the industry became too good at the game, shale-gas production soared, and prices crashed. There is an open border between the U.S. and Canada and prices are inevitably dictated by demand from the populous coasts and the southern states.

To make matters worse for Canadian producers, they are at the "end of the line," far from market. They typically receive a discount to Nymex for their product and must be among the lowest-cost producers on the continent if they are to survive, let alone prosper.

Price discrepancy

Typically, it is understood that there is a strong correlation between oil and gas prices. One can substitute another in certain applications, and outside of North America, gas contracts tend to use oil as a benchmark from which gas prices are derived. An increase in the price of oil will probably lead to an increase in the supply of gas.

In North America, spot prices dominate, and the price of gas is not directly determined by oil. Rather, demand for and supply of gas dictate the price in an open market. In an environment where gas and oil projects compete directly for capital, equipment and people, many observers argue that the price of gas must increase dramatically before people start drilling substantial numbers of new wells.

According to Peter Tzertzakian, chief economist at oil and gas investment fund manager Arc Financial and one of Canada's leading energy economists, "Oil and gas companies are called that because they look for both. But why would a company that's altered its business plan and mindset to start looking for oil ever go back to looking for gas? There is a massive profitability gap.

"So even if the price of gas does climb, I don't think too many companies will be going back to gas. Even technology that was being used on the shale-gas side is now being applied to oil with increasing success. It's going to be a big change. The question is, when will it happen, and I don't think it's going to be this year, but possibly after next winter."

According to Ryan Shay, co-head of investment banking at Cormark Securities, "Most people are focused on the supply/demand balance for natural gas, so if gas jumps to $5 there are a number of gas projects that will get drilled. But, if you talk to the service companies, they are fully utilized right now with oil. Even if gas does go up, nobody is going to shift dollars out of oil projects into gas at $5 or $6. So gas has to really rocket up to get somebody off of oil. Everybody thinks we have all this cheap available gas, but at some point we're going to be short by a molecule and we'll switch to being under-supplied. And as soon as that happens, they'll realize there's no equipment available to do anything outside of high-margin oil drilling."

Robert Hodgkinson, CEO of Vancouver-based Dejour Energy Inc. (which owns oil and gas assets in Alberta and the U.S.), notes that the market has a habit of righting itself. "The beautiful thing about technology is that it's naturally deflationary. The cheap price of huge quantities of gas is going to help the reformation of the industry so we get to have serious growth again...Everyone's really hot on oil right now. It's interesting that there's a huge oil glut in the States, and that's going to persist for a period of time. Having said that, oil is the international energy commodity and the price will be reflective of that.

"The U.S. is very political and you can see this move to gas. As it takes hold, there'll be exponential growth. The pipeline expansion means that the availability of gas to market is now beginning to happen on a significant basis. It doesn't take much to maintain these leases, and so as long as you do that, you've got value-add at a very low cost. You just have to pick your time."

In the current world of $4 gas, it's hard to justify new gas wells unless they are drilled to ensure continued land tenure. However, there exist some fantastically economic plays in the WCSB. For Painted Pony, an early mover in the northeast British Columbia Montney play, the economics stack up at virtually any gas price.

As Painted Pony CEO Patrick Ward notes, "It's still working for us. We're either lucky, blessed, or really smart for being in the right place; a place that has a great reservoir, access to infrastructure, and a great royalty structure. Where we are in the Montney is the best of the best, we can make it work at $1.5 per Mcf. The play is equivalent to the tar sands in terms of gas in Canada."

The economics

With the price of gas in the doldrums, and forward prices indicating it will stay that way for some time to come, operators are focusing anew on costs. "Cost structure is critical and surface infrastructure is key to that," insists Delphi Energy CEO David Reid. "We own pipelines and processing plants, so that gives us the lowest possible price structure. Surface infrastructure is to a large extent a fixed cost, as we grow production our costs come down on a per-unit basis."

In 2008, Delphi's cost per barrel was $10.37. In 2011, it is looking at producing at a cost of $7.10 per barrel and can add production in key areas at an operating cost of $6 per barrel.

Many Canadian E&Ps had been shielded by prudent hedging through 2010 and early 2011. As today's forward prices reflect a longer-term pessimism about gas prices, many gas producers are choosing to take the downside risk and bet on increased prices going forward by not hedging out as much of their production.

Says Delphi's Reid, "In 2009 we earned about $22.5 million from hedging; in 2011 we are looking at the $5-million mark."

Delphi chose to lock in 52% of its 2011 gas production at $4.93 per Mcf, which, judging by this winter's spot prices, appears to have been a good move.

According to Dejour's Hodgkinson, "We have had to refinance in the public market in order to strengthen our financial position, and we successfully achieved our objectives. Currently, the joint-venture market is beginning to heat up again and present options. At the same time, the availability of project capital is becoming more accessible for companies such as ours, giving us another potential alternative to equity financing."

Diversification

Diversification is key for Canadian gas producers. Perpetual Energy, the new name of the high-yielding Paramount Energy Trust, is repositioning itself. "Our production today is 95% natural gas," says CEO Susan Riddell Rose. "In two years it will be 75%. What will move us into a more balanced direction is the heavy oil that we have put into our inventory. There are several exploration targets that we have as well. We are in a highly concentrated asset basin in shallow gas, and we have been repositioning our asset base to add assets in the western part of Alberta."

Investors are still wary of what they perceive to be "pure-play" gas companies; however, there is appetite for "gas plus" companies that have the ability to add something to their offering. "People are intrigued by the vast array of opportunities that we have in our asset base and our ability to approach things in more of an entrepreneurial way," says Riddell Rose.

"Over the last 18 months, we have developed a gas storage project, which is a midstream operation that we run on a commercial basis. We completed the project a year earlier than many expected us to do. People still treat us as a pure-play gas producer, but they are sitting back and watching."

Thunderbird Energy Corp. is a Vancouver-based gas exploration company with assets in the U.S. In addition to its gas assets, it controls a large CO2 deposit that has the potential to add value to the company. The U.S. Department of Energy is looking to utilize the gas deposit as part of a trial CO2 CCS project.

"The reason that this project came to us is because we are in an area in Utah with existing coal mines and coal-fired plants," says Thunderbird CEO Cameron White. "On or near our property there are at least three deep wells that flowed from 3 to 4 million up to 15 million cubic feet per day of CO2, so we know there's a lot of CO2 there."

"The goal is to be able to prove they can sequester up to a million tons of CO2 a year underground, but they need to get the CO2 first. It's a one-stop shop for them—there's a source for CO2 where they can bring to the surface, compress, and sequester it back underground. For us, it will bring a lot of money in for infrastructure and it could potentially set us up in the CO2 sequestering business. It could also provide a large CO2 reserve for us that we could extract and sell."

Most of today's gas companies acquired their assets before the gas-price collapse. Some gas bulls were fortunate enough not to be tied to assets when prices started falling and have started building land positions in anticipation of an upswing.

"We started Edge in mid-2009 when gas prices were awful and the future was bleak, so we've been contrarian from the very beginning," relates Edge Resources CEO Brad Nichol. "We had a fairly tight shareholder group comprised of people who were convinced that gas is going to show some kind of a rebound, and we wanted to be prepared well in advance. Maybe we're a bit early, but we're accumulating a land base and trying to be as efficient as we can in building a business for $3 or $4 gas with the hope that gas will ultimately go to $6. If we're profitable at $4, we'll be highly profitable at $6.

"We're focused on gas but not so focused that we won't consider oil. In fact, we're just about to complete an oil acquisition that's opportunistic, shallow, and mature and that generates a lot of income with little or no effort."

Low prices bring opportunity

Even in the bearish world of today's North American gas market, teams with the right track record can attract significant investor support. "I set up a company called Berkley Petroleum, which we grew during the '90s on a 6:1 basis to 40,000 BOE per day. Berkley Petroleum was subject to a hostile takeover by Hunt Oil at Christmas 2000 and was eventually sold in March 2001," recounts Mike Rose, the most successful and celebrated gas man of his generation. "Duvernay was set up in summer 2001 with the same management and technical team and went public in February 2004 and grew to 28,000 BOE per day."

Rose and his team worked through the stampede, Calgary's 10 days of debauchery, to sell Duvernay to Shell for $6 billion.

With such a phenomenal track record, Rose can raise capital whatever the price of gas. Leveraging that, and the large amounts of capital he and his team had pocketed with the disposal of Duvernay, Rose undertook a land grab during the economic crisis. Needless to say, the discounts available were significant.

"We focus on the western side of the sedimentary basin, which contains more gas than oil. We set out to have two or three large core areas, with a large inventory, and strive to be a low-cost producer, which is essential in a volatile gas price environment."

In 2010, Rose took his new company, Tourmaline Oil Corp, public.

Tourmaline has assembled a significant land position and should be able to achieve the economies of scale so important if value is to be added to gas assets. "In the deep basin we will drill at four vertical wells per section; at two vertical wells per section we have 3,100 locations in inventory..., which is a tremendous amount of value for us to unlock and turn into production and recognized reserves," says Rose.

With gas trading at such a discount to oil, many believe that new markets for Canadian gas will be opened up. As Canada Energy Partners' Ben Jones and John Proust note: "The 20:1 price differential between gas and oil is unsustainable. If you can buy a Btu of heat for a third of the cost of a Btu generated by crude oil, people are going to figure out how to burn natural gas...Now is it going to be the Pickens Plan, or using gas-to-liquids technology? The jury's still out."

Liquids allure

In the Montney, South African major Sasol recently structured a large farm-in with Talisman at $30,000 a net acre. Jones notes: "The Sasol deal was done on the premise that they would build the first gas-to-liquids plant in western Canada...We think it's exciting that the feasibility study for the first gas-to-liquids plant in the country is being done adjacent to our land."

Across North America, gas operators are looking to drill liquids-rich gas targets. In Canada, the vast bulk of gas produced is not associated with oil but comes from gas-only fields. However, many of these targets have a high level of natural gas liquids (NGLs) in place. In the WCSB, the appetite for liquids-rich targets is even more pronounced. Due to the viscosity of bitumen, a high level of diluent is required to transport it, and natural gas condensates make an ideal diluent. While western Canadian gas suffers a discount to the typical North American market price, diluents produced in western Canada are close to market and thus attract a premium to typical continent-wide prices.

Compton Petroleum, a virtual pure-play Canadian gas company, recognizes the impact on economics that even a relatively small amount of liquids production can have on a gas well. "We are focusing our development drilling on liquids-rich gas targets," states CEO Tim Granger. "A well may produce a million or two of natural gas, but it will also do about 80-90 BOE per day (of liquids)."

With NGLs attracting a premium, "liquids make a huge difference in (the) economics," notes Yoho Resources CEO Brian McLachlan. Yoho was an early entrant into the Peace River Arch and has assembled a land holding that allows it to pick and chose dry or liquids-rich targets according to market conditions.

"Instead of waiting for gas prices to increase, we allocated all our efforts towards finding gas that has high liquids content with it, which will carry your day until gas comes back up," says McLachlan.

The pursuit of liquids is not limited to the juniors. Chris Summers at Devon says, "Currently, anything that's purely natural gas and doesn't have some strategic reason for investing in, isn't being invested in... The good news for us is that there are no imminent expiry issues with the large land base that we have... On the gas side we're still putting about $150 million dollars in, but only with liquids-associated projects."

Educating the investor that a "gas" stock might actually produce, or be able to produce more liquids (NGLs or crude) can be an uphill struggle. As Brian Dau, CEO of Anderson Energy, notes, "Right now the investor still considers us a natural gas company and the valuation of the stock is tarnished by the gas name. We're taking the gas decline, and replacing it with oil. So the investor will start to see that. In 2011 we will spend 100% of our budget on oil."

Montney: Gas at any price?

Prior to the collapse in North American gas prices, the Canadian plays attracting the most dollars and the biggest names in the oil and gas business were not light oil targets such as the Bakken, but the mega-sized, gas-rich shales of northeastern British Columbia and Western Alberta. Land auctions in the Montney and Horn River broke records in 2007 and 2008 as E&Ps fought for control of these massive and well-understood shales. In the July B.C. land auction, Montney assets sold for a record-breaking $610 million.

Ben Jones, CEO of Canada Energy Partners, notes, "Morgan Stanley recently conducted a study which identified the Montney as one of the top five shale-gas plays in North America." What makes the Montney, one of the most isolated oil and gas plays in North America, so attractive even in today's environment?

Risk, or lack of it, is key. As Don Gardner, CEO of Montney-focused junior Canadian Spirit Resources Inc. (CSRI), observes, "This is a low-risk play. The geology of the Montney is well understood and all around us majors are de-risking our property though their drilling programs.

"The attraction is that there is over a thousand feet of Triassic shale formation that's gas-saturated top to bottom," notes Jones. "Talisman has declared publicly that the entire thousand foot interval is commercially productive. Their Montney acreage is right next to ours, and they have up to 450 Bcf per section. One of the good things about Canada is that everyone has to submit their geological data to the province. Since that data is publicly available, you have a freedom of information unlike what is available in the U.S. It makes for a very competitive environment up here."

Despite this, some of the majors are pulling back from the Montney. Shell had farmed into some of Canadian Spirit's lands in 2008. Despite investing and demonstrating reserves, Shell chose to hand back the property in 2010. Even with the Shell pullback, Gardner remains confident that the assets will appeal to the larger companies who are interested in building their land positions. As Garner observes, "There has been a lot of activity around our area despite the downturn. We will probably sell out our assets within three years to a larger company looking to develop."

One might assume that, post-gas crash, things are quiet in the Montney. However, in February 2011, even as gas prices remained low despite a cold winter, Chinese national oil company PetroChina agreed to pay $5.4 billion for a 50% interest in 650,000 acres of Encana's Cutback Bridge business. Cutback Bridge is largely comprised of Montney land and the deal gives PetroChina some 255 million sq. ft/day of existing production plus exposure to significant drilling inventory.

Apache owns some 5 million acres in Canada and in 2010 purchased an additional 1.3 million acres from BP. Canada reserves represent some 28% of the company's global total and the Horn River is a key component of Apache's long-term North American strategy. Apache has a 50% working interest in 210,000 acres of the Horn River and in 2010 production reached 100 million cubic feet per day. Tim Wall, VP Canada at Apache, notes that "this year, activity will be limited, as I think it will be across the (gas) sector," –however, limited for Apache still means drilling an additional 10 wells in the Horn River this year plus completing a further 28.

Liquefied natural gas

What gives Apache the edge over its competitors in the shales of western Canada is a corridor to new markets. Apache is the lead partner in the Kitimat LNG project. The Kitimat LNG project comprises a new gas liquefaction facility and sea terminal 400 miles north of Vancouver on the west coast of Canada and an associated 287-mile pipeline linking the terminal to the gas distribution network in western British Columbia. Apache currently own 51% of the project with EOG Resources controlling the remainder. At the time of writing the partners had entered into an agreement to sell 30% of the project to Encana, leaving Apache with a 40% share.

In the words of Apache's Wall, "Kitimat completely changes the way you view our (Canadian gas) assets." Kitimat's initial capacity will be 700 million cubic feet per day (for 5 million tons of LNG a year). Apache's 40% share will give it exposure to 280 million cubic feet per day of export capacity, or 70% of its 2010 Canadian production.

Despite the fact that Kitimat will only be able to handle 4% of Canada's gas production, there is recognition that the facility will change the face of the Canadian gas sector. In the words of Painted Pony's Patrick Ward: "It doesn't make sense to be selling gas to the U.S. for $4/Mcf when we could be selling to Europe or Asia. Kitimat will be a game-changer for the country and the natural gas market in North America. Gas prices will go up when exporting becomes possible."

Resource plays

The collapse in North American gas prices has caught out many a Canadian junior. However, a focus on large unconventional plays with the potential to "go industrial" on the drilling and fracing may be the best way to drive capital values, if not short-term revenue.

Unconventional Gas Resources is a pioneer junior, the first commercial exploiter of coalbed methane in Canada. UGR's CEO Michael Gatens and his team bring a wealth of experience to the table when it comes to gas.

While fully acknowledging that current price of gas makes exploration and development of shale-gas targets challenging, Gatens notes that, "We take a longer term view of things and believe that gas prices will pick up in the medium term."

The current trend is for "resource plays," but Gatens notes, "I have been chasing big plays for years, so have most people, it's just now they are called 'resource plays.' It's more of a branding thing rather than a change in mindset. We are all looking for big, repeatable plays and we think we have some in the company."

As a privately held company, UGR can perhaps take a slightly longer-term perspective, though Gatens still has to keep an eye on an eventual monetization of assets. "Despite the collapse in gas prices, there has still been a lot of M&A and JV activity in our area, driven by majors and super-majors," he says. "We are looking for partners for some of our assets, if the price is right. Lager companies have a lower cost of capital and can leverage a brand to develop out the sort of assets we own."

Shale gas and ultra-large conventional targets may be the name of the game for the big boys, but several small and midcap players believe that they can build profitable operations around medium-sized conventional gas targets.

"The driving technology has been the concept of horizontal drilling with multistage fracturing," notes John Rossall, CEO of gas junior Prospex Energy. "That has allowed the large players to access shale gas. Shale is a much lower-quality resource than has been developed historically. It's a big leap down the curve of reservoir quality. So, the restructuring has been that the 'big guys' are all pursuing shale gas in Canada.

"That leaves the small guys with a strategic choice of taking the somewhat less abundant resources that are higher quality than shale," continues Rossall. "At last year-end, we had 12 million BOE of P+P reserves. That's 100 Bcf of gas. By staying in the niche of taking mid-sized assets and still economic projects, I'm never in competition with the big guys.... We are accessing reservoirs that are similar to what we have done in the past.

"All we're doing is using the new technology to further improve our economics. We're operating in places where there are already vertical wells drilled and completed. We can characterize the resource, based on the data we already have, before we go into it...There's a lot of overlooked potential in conventional areas."

While most of the focus in western Canada in recent years has been on assembling unconventional "resource plays," some teams believe that significant value can be built by acquiring unfashionable conventional assets on the edge of the fairway.

Manitok Energy's CEO Massimo Geremia explains: "We have deliberately followed a contrarian strategy, both in terms of asset class and location.

"Our main focus is oil and liquids-rich targets in the foothills area of western Alberta, complemented by lower-risk heavy oil opportunities. The foothills have great infrastructure because of the development associated with deeper targets, but not enough attention has been given to the conventional targets."

Geremia is searching for large, repeatable targets, but keeping costs down has been key from the onset. "We acquired land for as little as $150 per acre and are carefully located in areas with surplus gas processing capacity. Our gas is liquids-rich, but you have to structure your deals and target your money to keep your costs low today.

"Our team has many years experience in the area, most of which they accumulated with Talisman...but we still need to educate the investor about the foothills opportunity and demonstrate through achievement that we are the company to realize that opportunity."

At the end of the 2010/2011 winter season, Manitok tested its newly drilled Stolberg well to an IP of 739 BOE per day, including 100 bbl/day of NGLs, suggesting that there is life and liquids in the foothills story still.