Peyto Says Cost Control Key To Its Success

By Lynda Harrison

Peyto Exploration & Development Corp. has nearly tripled its size in three years -- based on first-quarter 2013 production of 55,372 boe per day versus first-quarter 2010 output of 20,652 boe -- at a time when, arguably, the industry around it is struggling, its annual general meeting heard.


The company's production per share, reserves per share, asset value per share and -- despite falling gas prices -- cash flow per share have all been growing over time, Darren Gee, president and CEO, told the meeting.


While the company has changed much over the past 10 years, its strategy remains, he said.


"We still use our technical expertise -- which has now been enhanced with 15 years of experience in the Deep Basin -- to come up with opportunities to invest shareholders' capital to generate the maximum possible return," said Gee.


The company is still operating in the same areas it was 10 years ago -- in the Alberta Deep Basin, which still offers more than enough opportunities and where, just like 10 years ago, last year it was the most active driller, drilling four times as much as Encana Corporation, he said.


While doing the same thing over and over again may be boring, Peyto's investors would probably agree that being successful is better than interesting, he told the meeting.


The company's land position has grown to more than 620 net sections now from 76 net sections 10 years ago. "That's a compound annual growth rate of 23 per cent on our land base," said Gee.


Many people say there is no more land available in the Deep Basin yet Peyto manages to add acreage containing drilling locations each and every year whenever it wants, he told the meeting.


"I think that is because this business is not so much about capturing land and capturing resources as it is about execution. If you can't execute on your lands, what's the point of having it?" he asked.


The company ensures it is profitable by controlling its costs, and capital costs have risen while cash costs have tended to decrease, so while the company's strategy has been consistent, how it executes that strategy has changed in the past 10 years, the meeting heard.


To illustrate his point, Gee indicated a typical well drilled using the company's old method and compared it to the way Peyto drills wells now, as of three years ago.


The company used to drill only vertical wells. It drilled 650 of them in its first 10 years, sometimes combining two zones in one well, but always having to fracture stimulate the tight sandstones to get them to flow.


Since fall 2009, it has drilled more than 250 wells -- almost one million metres -- the "new way," and its inventory of future locations has grown "way faster than it used to grow," because it is unlocking even greater potential resources through more zones, allowing it to develop reserves more rapidly, he said.


The example "old way" well was a typical Sundance well, a 2,700-metre, dual-completed Cardium/Notikewin vertical that took 28 days and $1.2 million to drill and 25 days and another $1.2 million to complete. The well required 80 tonnes of sand in the Notikewin and 70 tonnes of sand in the Cardium.


Production results were the typical two mmcf per day from the Notikewan initially, decreasing to a few hundred mcf per day while the Cardium came on at 200 mcf per day with a "pretty flat" decline rate.


Full cycle, the well cost about $3 million for 2.5 bcf equivalent of reserves, or $1.24 per mcfe ($1.75 per mcfe finding, development and acquisition costs in 2013 dollars).


New wells use horizontal multistage fracs with every stratigraphic layer drilled separately, often from the same surface site.


Nowadays, a typical Notikewan well is a 4,300-metre horizontal that takes only 20 days to drill, including the 1,500 metres of horizontal lateral through the formation -- all because of the advances made in drilling technology and efficiencies, Gee said, citing drill bits and mud motors as examples where this has occurred.


The new-way wells take another 11 days to complete by fracturing, with 480 tonnes of sand, and cost a total of $2.9 million to drill and $1.5 million to complete.


But to compare it to the first well, one must also consider the cost of drilling a horizontal Cardium well, he noted. This typical, 3,100-metre well now takes 28 days from spud to rig release (it takes longer to drill sideways in the Cardium) and costs $2.2 million to drill and $2.9 million to complete, with 360 tonnes of sand.


Had it been drilled from the same site as the Notikewan well, Peyto would have saved about $350,000 in rig moving costs and site construction costs, said Gee.


Total FD&A costs: $1.53 per mcfe in 2013 dollars.


Results for the two wells were about six mmcf per day for the Notikewan, declining to two mmcf at the end of the first year, and the Cardium came on at about 1.7 mmcf per day, declining to 600 mcf per day.


Reserves assigned to the horizontal Notikewan and Cardium wells were 4.3 bcf and 3.1 bcf, respectively, and Peyto has recovered about 20 per cent of that in the first year.


It would take more than six of the old wells versus four of the new wells to drain the same-size area, said Gee.


"We would have to drill three vertical wells the old way with dual completions to equate to the same amount of reserves developed as two horizontal wells this new way," he said. "Arguably we could still do it cheaper the old way if we could do it at the same surface costs and prices that we had 10 years ago but sadly we can't do that because costs have not stayed the same as a decade ago."


Estimates are that at today's costs, the old way with the vertical wells would cost 30 per cent more to drill and complete, and probably another twice as much for the tie-ins and installation of wellsite facilities, said Gee.


Peyto is also doing a few things different operationally from 10 years ago, he added. These include stripping additional liquids out of its gas stream using a Peyto-designed "cheap cut" facility as of last fall.


If the economics continue to make sense, the company can enhance all its facilities this way, he said.


It is also displacing an increasing amount of diesel from its operations in exchange for natural gas. "There's no point in buying this expensive fuel when we produce a perfectly good, cheaper alternative," said Gee.


Last year, Peyto invested about $1.5 million to build a compressed natural gas fuelling station at its Oldman gas plant that will allow it to use natural gas in drilling, completions, plant operations, power generation and field vehicles, for cost savings of an estimated $5 million a year.


Of course, Peyto's gas prices have not risen in the past 10 years; in fact they have dropped, much to Gee's frustration. Prices realized in the last three years have fallen 70 per cent versus the decade prior, he said.


Yet at the individual well level and the corporate level, costs to build have climbed. "Total FD&A costs on a proved producing basis is up 144 per cent over the last 10 years, which means we have seen about a nine per cent compounded inflation in our costs over the last decade, which is pretty big," he said, adding inflation has hit services, labour, drilling rig rates, materials and fuel.


Interestingly, it costs Peyto less to produce gas, partly thanks to lower royalty rates but also due to maintaining the same cash costs over the past decade, said Gee. Meanwhile, its peers have seen an increase of 80 per cent in their costs, he added.


Peyto's cost control measures were especially important last year, when the company endured the lowest gas prices in its history -- $2.30 per gigajoule on average -- and yet despite this, Peyto recorded a 22 per cent profit margin, said Gee.