Attractive economics, massive resource potential, diverse investment options. Canada’s Montney Shale may not be the first unconventional resource to spring to mind, but the description fits. And there’s more: Montney players’ stocks offer a 30% discount to American investors due to the current U.S. dol¬lar/Canadian dollar exchange rate. (All amounts are in Canadian dollars unless otherwise noted.)

A presentation on the Montney’s future drew an attentive audience at EnerCom’s The Oil & Gas Conference 21 held in Denver in August. Juan Jarrah, oil and gas equity research associ¬ate with TD Securities Inc., spoke on a panel about the play. In separate talks, Montney pure-play E&Ps Advantage Oil & Gas Ltd. and Painted Pony Petroleum Ltd. discussed techni¬cal approaches, capex, rates of return and the liquids-rich sweet spots that are giving their economics increasing heft.

Good and getting better

Jarrah laid out the investment case for the mighty shale, which straddles the border of Alberta and British Columbia.

First off, he said, the Montney is big, thick and there’s a lot of it. The play is roughly the same size as the Marcellus (50,000 square miles) but much thicker—as thick as the Eiffel Tower is tall (1,062 feet). As for the resource size, a joint assessment made by the National Energy Board, the British Columbia Oil and Gas Commission, the Alberta Energy Regulator and the British Columbia Ministry of Natural Gas Development in late 2013 estimated the ultimate unconventional potential at 449 trillion cubic feet (Tcf) of marketable natural gas, 14.5 billion barrels (Bbbl) of marketable gas liquids, and 1.125 Bbbl of marketable oil.

The Montney’s only getting better, Jarrah said. Horizontals have continually outperformed prior-year results on the basis of 90-day and 365-day initial production (IP) rates. Longer laterals, bigger and better-placed fracks and smarter completion designs are driving improve¬ment, and all are still in the early stages.

Positive revisions to Montney EURs have consistently driven year-over-year corporate production and reserves growth. The play’s economics are as attractive, if not more so, than many of the best U.S. shale plays, Jarrah said.

The Montney faces challenges on the reg¬ulatory side, however. Canada’s new federal government is seeking to place a national price on carbon emissions following its commitment at the Paris Climate Conference to reduce emis¬sions in line with the global target of 2 degrees C. Concerns over a potential carbon tax could hinder growth not only in the Montney but throughout Canada.

Additionally, many provinces are proposing their own environmental regulations. Over the next six to 12 months, the federal government will attempt to harmonize with the provinces a countrywide price on carbon. The out¬come of this effort and the results of the May 2017 British Columbia provincial election will provide greater perspective on regulatory developments.

Scale drives M&A

Between 2009 and 2012, resource capture was the primary trend in the Montney as large companies paid up for acreage. Over the next couple of years, operators turned their attention to delineating the resource through drilling.

Going forward, Jarrah said, the main theme will be acreage consolidation via A&D. Economics of scale and access to capital and infrastructure will shape companies’ decision-making.

Prices per acre have increased as companies demonstrate their willingness to place higher value on coveted acreage. Birchcliff Energy Ltd. and Seven Generations Energy Ltd. recently purchased concentrated land posi¬tions from early entrants Encana Corp. and Paramount Resources Ltd. In late June, Birch¬cliff agreed to pay Encana US$488 million for its Gordondale properties in the Montney. The sale includes 54,200 net acres and asso¬ciated infrastructure in northwestern Alberta. In early July, Seven Generations struck a deal with Paramount to buy Alberta assets for about US$1.4 billion (including assumption of debt), adding about 30,000 barrels of oil equivalent per day (boe/d) of production and 199 MMbbl in proved reserves.

Jarrah believes E&Ps will consolidate British Columbia acreage positions next. Regional oper¬ators’ holdings are fragmented, and they seek via deals to access pipeline capacity and alle¬viate regional pricing differentials. The outlook for LNG exports—the Montney is a key supply basin for terminals on Canada’s west coast—will also influence A&D.

Predictably, prices per flowing barrel and for 2P reserves have decreased in recent years, because acquisitions during the resource-capture period focused on future reserves and future production, implying higher multiples on exist¬ing reserves and production. Today, companies are focused on ratcheting up production and reserves on existing acreage in order to generate economies of scale.

Powering up

While Canada’s greenhouse gas regulatory environment remains uncertain, the continued development of the Montney is assured by its compelling economics.

Montney specialist Advantage Oil & Gas, traded on the Toronto and New York stock exchanges, has been growing rapidly through the downturn. The E&P, with a market cap of $1.7 billion, has been drilling in the Glacier area of the play since 2008.

Andy Mah, president and CEO, said that in second-quarter 2016, the company deliv¬ered 68% production growth along with top-quartile well results. Total corporate cash costs were just 59 cents per thousand cubic feet equiv¬alent (Mcfe)—a metric that, with low operating costs, drives the play’s economics.

Mah highlighted the company’s $19 million in surplus cash flow posted for the second quarter. “Certainly our capital spending was lower in the second quarter, but to accomplish that [cash flow] was a feat that no one else could touch in the basin,” he said. “We paid down about $9 million in debt in the second quarter as well.”

Advantage has avoided the excessive lever¬age that has sunk many others during the downcycle. “As of June 30, our bank debt posi¬tion was just under $200 million out of a $400 million bank line,” he said.

The company’s total 2016 year-end debt to trailing cash flow at a gas price of $2 is esti¬mated to be 1x.

Hedging lends stability to the company’s finances. “We’re hedged out through 2017 at varying levels, with about 50% of production at $3.60, then $3.20 and then $3.08, I believe,” he said. “Three dollars is a heck of a business for us. At $2.50, we can grow just fine, and we can sustain at below $2.

“We’ve put the company in fantastic shape financially and are able to look at other val¬ue-adding opportunities not just in terms of organic growth, but also from an M&A per¬spective in our immediate area,” Mah said. “Recently, we added 12 net sections of Mont¬ney lands in and around our existing land blocks through government land sales.”

Advantage is delivering about 22% average annual production growth in the 2015 to 2017 period and intends to be within a 15% to 20% growth rate in the next three years.

A low-cost structure has been a cornerstone in the company’s strategy. “When we got into this play in 2008, I said, Guys, if this works at all, we’ve got, potentially, a major resource,” Mah said. “Let’s not screw it up in the first five years. If this is a world-class asset, what we need to do is continue to push forward and try to be the lowest cost producer out there, to own and operate all of our infrastructure and Glacier gas processing facilities.

“Today, we own it, we operate it and have full control of our future.”

Balance sheet and operational financial flexi¬bility allow Advantage to extract value from its assets. It has over 60 MMcf/d of surplus well deliverability from eight completed standing wells in the Montney, and 14 more drilled but uncompleted wells, which it plans to complete before year-end.

“Those wells help us offset declines, but also help us ramp production in 2017 from 200 million [per day] to about 240 million to 250 million to fill out our plant capacity. Additional wells we are drilling in 2016 probably won’t be completed until late-2017 and into 2018.”

Unlike a number of other Montney operators, Advantage owns all of its midstream assets. It plans to add 100 million a day of additional plant capacity to its Glacier plant in first-half 2018. Further, it owns plenty of sales gas takeaway, with 200 MMcf/d of additional capacity for a total of 400 MMcf/d on pipes.

Nuts and bolts of growth

Advantage’s land position is in the central fairway, where drilling was launched in 2006. It’s grown production from its Glacier area to 210 MMcfe/d, or 35,000 boe/d, and Mah antic¬ipates “doubling our growth in the next couple of years.”

The company has uncovered one of the “prime sweet spots” in the play fairway, Mah said, where gas and liquids-rich production adds significant value.

This year its capex program is $125 million, with about half earmarked for drilling new wells and completing standing wells, and half for pipeline looping and other activities.

It has an estimated 1,100 future drilling locations at the Glacier prospect, which is com¬prised of 1,000 feet of rock in five developable layers with four wells per layer. Production is both dry gas and liquids-rich.

“When you lay that out across Glacier, you get about 20 wells in each section,” Mah said. “Today we’ve only drilled 170 wells. What’s exciting is all of it is working.” There is a sixth layer that Advantage plans to drill in the next few years.

Mah said that recent “top quartile” wells are yielding production of 10 MMcfe/d to 20 MMcfe/d. Increasing the frack count has improved long-term production in all layers. Costs are coming down substantially and today are about $4.5 million for the Upper Montney layers, and $4.8 million for the Middle and Lower Montney, all with 25 fracks.

In 2013, Advantage implemented a significant change in its drilling and completion designs. That winter it began using slickwater-only fracks and increased the number of stages to an average of 19, with openhole packers.

“We’re just starting to use cemented ports, which will give us even tighter spacing,” Mah said. “Our analysis since 2008 has told us that frack spacing is more critical than the amount of proppant. We’re seeing wells that are behav-ing and heading toward our top-quartile curve, which is about 9 million a day for a 30-day IP.”

The company is currently concentrating on its Lower Montney drilling and completions using 25 frack stages, openhole packers and cemented ports. To lessen damage from frack-sand flowback, it restricts production to less than 10 MMcf/d for the initial six months.

Longer laterals and tighter spacing will be tested next.

In the Middle Montney, Advantage has determined three layers are liquids-saturated. It changed up its completion design to use more than 20 fracks and cemented ports and is evaluating results. “The last 10 wells have been doing really well, they’re hanging in, and they’ve been flat [in production],” Mah said.

At the end of the day, it’s all about the economics. Looking at data for dry gas and liquids-rich production from the Upper, Mid¬dle and Lower Montney, and using C$3 flat pricing and US$55 WTI, “we’re generating rates of return of at least 45% [for the type curve and cost] ranging up to almost 90% [for the higher IP and EUR case],” Mah said.

Northern Montney

Painted Pony Petroleum has made a name for itself in the Northern Montney area in north¬west British Columbia. The company, which went public on the Toronto Stock Exchange in May 2007, expects to exit 2016 producing 240 MMcfe/d (40,000 boe/d), a 166% increase over fourth-quarter 2015. It has a market cap of $850 million, debt of $173.6 million at the end of the second quarter and is fully funded from operations and its $325 million, two-year credit facility.

President and CEO Pat Ward noted at the Enercom event that the company prides itself on having both five-year and 30-year strategic plans.

Painted Pony has built up a reserve base of more than 4.6 Tcfe with only about 25% to 30% of its land developed. Takeaway is not a problem, as it has a strategic alliance with Alt¬Gas to process its gas as well as “excellent” pipeline egress to North American markets, Ward said.

The Northern Montney is overpressured, and “that’s what gives us the juice to make our wells perform really well,” said Ward. Associated NGL, particularly in its southern Townsend block, can add up to 60 bbl of liq¬uids per MMcf. Some 60% of that is conden¬sate, which earns a premium price in Canada as a diluent for oil sands operations.

Three layers in the Montney are currently producing on Painted Pony’s lands, with an eventual five layers producing when full devel¬opment takes place, according to Ward.

Infrastructure buildout is central to the five-year plan. Eventual expansion of the recently commissioned 198 MMcf/d AltaGas Townsend facility as well as other processing facilities in the area will enable Painted Pony to increase production volumes to more than 600 MMcfe/d by 2019. The company currently supplies gas to the largest utility in British Columbia, Fortis, and “we’re talking to petrochemical companies and others about long-term gas contracts where they would establish a floor and Painted Pony would establish a ceiling,” Ward said. Also, it is well-positioned to send its production to LNG plants planned by Petronas (Progress Energy Canada Ltd.) and others on the West Coast.

Painted Pony set its 2016 capex at $198 million with an expected $77 million in cash flow, and it anticipates drilling 31 net wells and completing 30 others by year-end. The goal is to keep growing cash flow and reach free cash flow in 2019. “As we ramp up in 2019, we’ve got free cash flow [$69 million], we’re not spending cash flow and we’re still growing at a very rapid rate,” Ward said.

Reducing costs is key. “Our G&A costs per Mcfe are down to about 19 cents this year and 12 cents for next year,” he said. Operating costs for 2016 are 70 cents per Mcfe, and the goal for 2017 is 60 cents.

Hedging Growth

Like Advantage Oil & Gas, Painted Pony hedges. It has more than 100% of current pro¬duction hedged because its banks have allowed it to hedge to future growth. “Hedging allows us to ramp up and have the assurance that the bank lines will stay with us as we grow,” Ward said.

Ward emphasized the value of a royalty structure British Columbia put in about 10 years ago that results in the company having a $2.2 million royalty credit for every well drilled. Regardless of fluctuations in the credit based on natural gas prices, “we get 150% to 200% payout of our well before our royalty jumps beyond 3%,” he said. “During the five-year plan, we figure we’ll average about 3%.”

Ward called the company’s wells “top per¬formance,” with average peak rates in the top decile of its peers. Painted Pony has 2 Tcfe proven reserves and expects more as it con¬nects additional production to the AltaGas plant. “More importantly, we have about 8.8 Bcfe booked per well, the largest of any Montney producer on average for wells,” Ward said.

The company’s recycle ratio also tops those of many of its peers, at 7.5x for 2015 2P and 1.5x for 2015 1P reserves (finding and devel¬opment). Its 69% growth in reserves per share also places it at the top of the heap among gas-weighted names, he said. Its finding and development costs are falling rapidly, from $1.60 per Mcfe in 2013 for proved plus prob¬able to $0.16 in 2015. And, its wells’ average peak month production rate is 6.2 MMcf/d, twice that of average comparable wells in the Montney.

Technology innovation has paid off for Painted Pony. It has switched from using plug-and-perf fracks with cluster perfs to an openhole ball-drop system on parallel pairs of wells. “What we found is we were getting better results, it was considerably cheaper and we have better well performance,” Ward said. Fracking wells in pairs has doubled its type curve at less cost.

The company estimates an average of $4.8 million to drill, complete and equip wells on a pad. “We’ve been consistently breaking that number, and we’ve done a number of wells under $4 million all in,” Ward said.

Painted Pony’s Blair, Daiber and Townsend wells make a good rate of return even at $2.25, he said. On the high-rate, liquids-en¬hanced Blair and Daiber wells, the IRR is 136% with a 12-month payout period. In the Townsend liquids-rich sweet spot, the IRR is nearly 100% with payout in 14 months. In the latter, technology innovations have doubled recovery to 1 Bcfe in the first six months.

Next year should be a busy one for Painted Pony. “We just upped our budget by about $20 million because our [processing] plant came on early, so we’re accelerating into 2017. We’ll drill another six wells, complete two extra wells and tie in some wells that we got in our recent land swap.” The swap is rumored to be with Petronas.

“Infinite gas” is how the company’s employees describe its holdings, Ward said.

“We have a 30-year plan where we con¬tinue to ramp this up to over 1.2 Bcf/d. We can go beyond that, but we can hold flat for the remainder of that 30-year period with the reserves we see in our land base.”

Charles Hepper is a writer with EnerCom.