As the perfect storm of slumps hits gas markets, operators are doing their best to keep the gas sector from falling off the cliff

Oilweek — By most accounts, this oil and gas industry slump is worse than that of 1980 to ‘81. Heavily gas-weighted producers are taking a tag-team beating from an economic collapse that has gutted demand and a step-change in technology that has flooded the continent with shale gas.

For a couple of years now, persistently low gas prices have dogged the industry-with the exception of a brief run up last year on the coattails of oil´s spike to US$147 a barrel. Companies with the option to focus away from gas on their oil properties by now have largely done so. And as gas prices flounder around C$3 per thousand cubic feet, most pure-gas players don´t see any reason to bring on new production.

To ride out the slump, companies have resorted to the tried-and-true strategies of disciplined cash flow management, forward-selling production, even laying off employees. But this downturn is shaping into something more than a typical downcycle, which may yet call upon more than a just a typical response.

Crystal ball

Everyone agrees that $2 gas isn´t sustainable, but saying when and to what extent gas prices will strengthen is anybody´s guess in this era of unprecedented gas prices volatility.

In his Sept. 8 market note, FirstEnergy Capital Corp´s Martin King talked of a natural gas market capitulation. "Large-scale shut-ins of natural gas in western Canada are underway, marking the first deliberate price-driven shut-ins of Canadian gas since the early 1990s," he wrote.

With Canadian gas storage at full capacity and some regions of the United States running short on storage space, shut-ins are a symptom of a market that simply has too much gas. The good news, according to King, is that by October natural gas prices should increase slightly and by December, Canadian shut-in volumes are likely to be staged back into production.

An assortment of factors go into price forecasts, from storage levels and liquefied natural gas imports to seasonal weather guesses and the extent of a U.S. economic recovery boosting gas demand, but gas declines and drilling cuts are a big determinant that currently sees little consensus.

Cam Bailey, the top executive at Fortress Energy Inc., a 100 per cent natural gas weighted Calgary-based junior, says a serious gas shortage may be developing. By implication, higher gas prices may come sooner than expected. He offered his market assessment in his company´s second-quarter release, and based his assumptions on average per-annum production declines in the U.S of 35 per cent.

Investment bank Tristone Capital Inc., on the other hand, sees more moderate per-annum U.S. declines of 27 per cent, and forecasts gas prices strengthening later this year, then averaging US$6.75 per thousand cubic feet (mcf) at the Henry Hub and C$6.45 per gigajoule at the AECO hub in Alberta in 2010.

Peter Tertzakian, chief energy economist at Calgary-based ARC Financial Corp., has said he expects gas prices between $5 and $6 in 2010, basing his estimate on declines in the mid-20 per cent range, among other factors.

But there are less-optimistic forecasts as well. Jen Snyder, the head of North American gas research for Wood Mackenzie, told a joint Canadian Energy Research Institute/Canadian Society for Unconventional Gas conference in Calgary recently that a quick turnaround isn´t in the cards.

"We´re operating in a completely different paradigm for North American gas markets now, certainly relative to expectations of three years ago," he said. "We´re expecting, over the next two years, a pricing environment in North American markets of Henry Hub price expectations in the US$4.50 to $5.50 per mmBtu range in 2010 and 2011, before moving up in 2012 and 2013 and extending on to 2020 with gas prices moving within the range of US$5.50 to $6.50 per mmBtu."

Producers

Paramount Energy Trust´s Susan Riddell Rose likes to say Paramount is unlike other heavily gas-weighted producers. For one thing, the company seems to have a particularly good crystal ball of its own.

"We anticipated the downturn in gas prices about a year and a half ago," she says. "So we´ve been hedging gas on the forward market at much much higher prices than where they are right now."

As part of its marketing program, Paramount focuses on a number of variables, including understanding the gas price cycles. Seeing a coming wave of shale gas production, the company hedged close to 60 per cent of its gas north of $7 through until April 2011.

"So Paramount Energy Trust is fine," Riddell Rose says.

Of course, Paramount has unhedged gas production squeezing cash flow and clipping its borrowing power, but a strong balance sheet still allows it to view some of the market developments as opportunities.

"Our most recent acquisition was Profound Energy Inc.," Riddell Rose says. "And we´re looking for other acquisitions." She notes that the best acquisition opportunities are currently on the gas side.

The Profound Energy deal closed in August. It´s in the Pembina, which is an old Cardium oilfield, but there´s also gas, which is the focus of this purchase. Paramount´s objective for the acquisition was to diversify its shallow-gas portfolio into more resource-style plays.

Cash flow at Peyto Energy Trust has taken a big hit, but with possibly the lowest production costs in the industry and an active hedging program, the Deep Basin producer is one of the few still drilling. By the end of the third quarter, it expects to double its number of wells drilled so far this year to a total of 20.

What is remarkable is that even at these commodity prices, Peyto´s unhedged gas production makes money. Company president and chief executive officer Darren Gee breaks down Peyto´s production cost as follows: $0.50 an mcf gets the gas out of the ground, $0.50 goes to general and administrative costs including bank interest, and another $0.50 for royalties totals a scant $1.50 per mcf.

"We operate all our production, we control it and keep very close tabs on it, so we´re still making positive cash flow from our production, even at $2 gas prices," Gee says. "But $3 a boe [barrel of oil equivalent] netback is not a lot of cash flow when you´re used in making $25 or $30 a boe netbacks."

As for his hedging program, rather than trying to beat the market, Gee takes the long view and aims to just level out the volatility.

"If you average out the gas price in the last five years, most companies would say, ‘Yeah, we can make money at that,´" Gee says. "Nobody can stay in business at $2 gas. At $12, everybody´s flush with cash. If you could average out to just get the $6, you´d be quite happy to conduct your business in a prudent way."

Almost half of Peyto´s summer production was forward sold a year ago. It continues to layer in new hedges-November gas for $4 an mcf-and a small portion of its gas production is sold as far forward as 24 months. At any given time, the company has about half its production sold into forward markets.

"If we were entirely unhedged right now, it would be very difficult to be working in this industry the way we are," Gee says.

And the way Peyto is working right now is building for the future. Its modest counter-cyclical drilling program takes advantage of lower service costs to build new production for when gas prices strengthen, but also to test some new technology in the Deep Basin.

Horizontal drilling with multi-stage fracing has been the key to tapping Saskatchewan´s Bakken and Shaunavon tight oil plays, British Columbia´s hybrid shale/tight gas Montney, and is seeing success in B.C.´s Horn River Muskwa shales. But little has been done with it in the Deep Basin. Gee believes it shows strong potential in these tight sands.

"Shale gas is really more source rock and tight gas is more from conventional reservoirs," he says. "In both cases, you´re dealing with very low-permeability rock, where you need massive stimulation to get the wells to flow. But you could almost argue that applying horizontal wells and multi-stage fracing to tight gas basins would yield even better results than in-shale formations because you´re working with a better quality reservoir in the first place."

In the Horseshoe Canyon, where the reservoirs are ancient coalbeds, all is quiet. The formula for this play´s low-volume, slow-decline wells was written earlier this decade in a statistical manufacturing-style vertical well approach.

Even Quicksilver Resources Inc., which bought the play opening MGV Energy Inc., isn´t drilling any new wells.

"We scaled back our work to be doing basically only that to meet expiries," says Quicksilver´s Joe Farley, senior vice-president and chief operating officer. "Given the pricing environment, we´re not getting much value for bringing production on."

As a subsidiary of a large U.S. company, the Canadian division benefits from an impressive company-wide hedging program. Roughly 80 per cent of its production is hedged through 2009 at prices in the neighborhood of US$8.50 an mcf, according to Farley. And 50 per cent of its 2010 production is hedged at a slightly lower price.

For now, Quicksilver´s focus has shifted from adding production to maintaining the production it has.

"We have wellhead metering on every well so that our operators and our staff here in our office can monitor all of our wells daily, looking for wells that are coming off, that need swabbing to identify areas where production is dropping out of the range that is predicted," Farley says. Taking timely action helps Quicksilver optimize its efforts in the fields, flattening its production profile.

If there is an upside to the drilling lull in the Horseshoe Canyon, it´s in the resulting reprieve around land access issues. The coalbed methane/water debate seems to have largely been resolved as the industry stepped up its communications efforts along with new regulations for water well monitoring in proximity to coalbed methane wells.

"Also, [landowners] just aren´t seeing as much activity now, so they tend to be more receptive in talking to producers," Farley says.

The Montney, meanwhile, has been touted by analysts as a "play that will be the last to fall off the table." This is where junior producer Orleans Energy Ltd. has about 80 per cent of its operations. In an email exchange with Oilweek, president and chief executive officer Barry Olson discusses some of the company´s challenges there.

"Certainly low gas prices have significantly reduced our cash flow, thereby reducing the capital that we can reinvest in our drilling programs," he says. "Junior oil and gas companies like Orleans rely on our free cash flow, equity financings, and bank lines as sources of cash to fund our capital spending programs. The recession has significantly lowered the share price valuations on most junior companies, consequently reducing the ability to raise equity via the sale of shares to investors. Orleans has utilized equity financings twice in 2009 to help fund very specific capital spending programs and to help reduce our indebtedness."

Currently, Olson has limited spending on exploration and development programs to free cash flow to minimize the company´s debt levels. Orleans is working with contractors and suppliers to better understand costs and to trim excess fat. It is also driving down the cost of operations by bidding out essential services and potentially shutting in higher cost production.

"For example, in our core Kaybob Montney gas property, in the spring of 2009, Orleans constructed a 19-kilometre, 10-inch pipeline to an underutilized gas plant that offered a reduction in processing and transportation fees of approximately 40 per cent, thereby reducing our overall operating expenses in the property by approximately 25 per cent," he told Oilweek.

Orleans forward sells a part of its production to preserve budgeted cash flow and to ensure execution of its capital programs. It has also extensively reviewed all of its producing assets and is selling non-core lower priority properties to focus on its core areas.

Echoing other top executives, Olson says operating its own projects is one of the keys to getting through difficult times by controlling the timing, the pace, and, most importantly, the priority of its capital spending programs.

If anemic gas prices persist as some predict, Olson says his top priorities will be "not allowing our debt to become unmanageable, focusing on reducing costs of services and operations, drilling only our highest netback most economic plays using only free cash flow, and being active in the acquisition market to look for accretive acquisitions and to maintain a constant dialogue with shareholders to ensure our priorities are in line with theirs."

Whether this energy industry slump is truly different from those that have come before it, as some suggest, remains to be seen. In the meantime, keeping the balance sheet front and centre is critical for all gas-weighted producers.

As tough as the conditions are, nobody is sitting on their thumbs. In fact, most every company has seized some opportunities that might have otherwise passed them by. Those opportunities can be reshuffling priorities through company acquisitions or sales assets, testing new technologies, optimizing existing production, finding new ways to reduce operating costs, acquiring land at a fraction of the costs from just a year ago, or simply doing a lot less but more efficiently.

That both the Alberta and B.C. governments have recognized the severity of the situation and responded with drilling incentives and royalty cuts has helped gas producers in both provinces and improved the region´s competitiveness.

Similarly, this downturn may be forging new resilience and determination into a Canadian gas industry that is emerging into a new continental natural gas market reality.