CONTENTS
MARCH.
in the news
9
Deeper wells mean higher repair costs for contractors
regional news
3 British Columbia
2 Northeastern Alberta
29 Southern Alberta
Falling oil prices a second chance for LNG, says AltaGas CFO
Low prices forcing oilsands efficiencies
DeeThree plans 29 wells this year
25 Central Alberta
3 Saskatchewan
Trilogy will “turn engine off” until prices rebound
Crescent Point top operator in 2014 on Saskatchewan drilling
7 Northwestern Alberta Birchcliff looking for balance with service companies to help them survive tough times
features Cover Feature
Sweet spots Liquids rich areas pushing Montney activity
every issue
6
Back to the future Low prices generate growing interest in recompleting older unconventional wells
Hunkering down Price and activity forecasts paint picture of a tough year ahead
Stats at a glance
33
Parts department
46
Political cartoon
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3
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Editor’s Note Vol. 27 No. 3 EDITORIAL EDITOR
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The crash in oil prices is getting all the ink in the media, but what’s happening in natural gas markets could be even worse, according to a recent presentation by consultants Bentek Energy. In early February, Bentek said there are almost 2,000 gas wells in the northeastern U.S. awaiting pipeline connections, and as those connections are made throughout 2015 a tsunami of new production is coming to market. Bentek estimates the 2,000 wells have a productive capacity of between seven and 10 bcf/d, equal to Alberta’s total production in 2013. As pipeline projects are completed this year, five bcf/d of new gas is expected to come on market. With this new supply expected to overwhelm demand, Bentek forecasts an average 2015 U.S. gas price of $2.56/mmBtu—lower than the recent NYMEX forward curve of $2.89/mmBtu. “We should see some pretty depressed prices moving into the rest of the calendar year,” said Bentek analyst Thad Walker. Bentek expects the weakest gas prices to occur in December 2015 as backlogged wells come on stream, adding the situation begins to improve further out into 2016 as demand picks up. Bentek said U.S. gas production in the past four to five years has largely been driven by the associated gas gains from oil and natural gas liquids (NGLs)–rich plays. Oil-driven drilling has been hammered by the collapse in U.S. oil prices to about $50/bbl from $100. NGL economics have also taken a dive. In the liquids-rich areas of the Marcellus shale play in the northeastern U.S., Bentek
estimates the half-cycle internal rate of return was about 44 per cent last October. It has since fallen to about 14 per cent—below what Bentek describes as the minimum 20 per cent threshold needed for an acceptable return While the backlog of wells already drilled is the biggest price damper, Bentek said producer hedges and increased drilling efficiency are also factors. While drilling activity has fallen by 320 rigs in the U.S. as prices have declined, those rigs that are working are drilling more wells. In January 2010, the number of wells drilled per rig per month was less than one. Today, each rig is drilling close to 1.5 wells per month. Bentek expects U.S. gas output to grow by 4.2 bcf/d in 2015 with the northeast contributing the lion’s share through 2015 and into 2016 due to the backlog of wells awaiting tie-in. Any way you slice it, this U.S. supply gusher is bad news for a western Canadian industry already being beaten up by low oil prices. Petroleum Services Association of Canada’s updated 2015 forecast released in January predicted 1,270 gas wells would be drilled this year, a far cry from the 13,850 wells drilled in 2006 and less than half the number drilled just five years ago. It looks like gas producers are going to have to wait another year for deliverance. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
N EXT I S S U E April 2015 Inside the Internet of things: Our annual automation and instrumentation feature. Plus a review of Bakken/Torquay activity.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.
OIL & GAS INQUIRER • MARCH 2015
5
FAST NUMBERS
,
Number of gas wells awaiting tie-in in the U.S., according to Bentek Energy
– bcf/d Productive capacity behind pipe in the U.S., according to Bentek Energy
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
OTHER
T O TA L
OIL
GAS
D RY
SERVICE
T O TA L
Feb
Feb
,
Mar
Mar
,
Apr
Apr
May
May
Jun
Jun
Jul
Jul
Aug
Aug
Sep
Sep
,
Oct
Oct
,
Nov
Nov
,
Dec
Dec
,
Jan
Jan
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission MONTH
Source: Daily Oil Bulletin
WELLS DRILLED
C U M U L AT I V E
OIL
GAS
Feb
Mar
Apr
May
Jun
Jul
Jun
Aug
Jul
Sep
Aug
Oct
Sep
Nov
Oct
Dec
Nov
Jan
Dec
Jan
Feb
Mar
Apr
May
*Year-to-date
6
MONTH
MARCH 2015 • OIL & GAS INQUIRER
*
MONTH
OTHER
TOTAL
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, January 2015 Source: Rig Locator
Western Canada, January 2015 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta British Columbia Manitoba Saskatchewan WC TOTAL
AC T I V E
OIL WELLS
Alberta
GAS WELLS
Jan
Jan
Jan
Jan
%
Northwestern Alberta
%
Northeastern Alberta
%
Central Alberta
%
Southern Alberta
%
TOTAL
Top Operators by Active Rigs
Drilling Activity: CBM & Bitumen
Western Canada, January 2015 Source: Rig Locator
Western Canada, January 2015 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
C OA L B E D M E T H A N E
EXP
Crescent Point Energy
Progress Energy Canada
Tourmaline Oil
ConocoPhillips Canada
Encana
Seven Generations Energy
Husky Energy
Royal Dutch Shell
Bonavista Energy
Paramount Resources
Alberta
BITUMEN WELLS
Jan
Jan
Jan
Jan
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
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IN THE
NEWS Issues affecting Canada’s E&P industry
Deeper wells mean higher repair costs for contractors By Carter Haydu
As longer, more complex wells work equipment ever harder in both drilling and completions, companies are seeing increased costs associated with the repair of that equipment. “With higher capital costs, of course, your day rates must go up as you have more capital upon which you must provide a return,” said Bob Geddes, president and chief executive officer at Ensign Drilling Services. “Your operating costs move up as well, because you are running higher torques, higher pump pressures, and there is just more rock coming out of the ground in the same period of time.” According to Geddes, as bit technology improves, crews can cut rock at a faster pace with higher torque, but running that higher torque requires larger mud motors downhole, which in turn requires more hydraulic horsepower at the surface and bigger mud pumps. With more torque downhole, companies need top drives that can hold back and turn at higher torques. “Basically, the capital cost to build a rig to perform these Canadian high-end horizontal wells has almost doubled in the last five to 10 years,” he said, adding companies are currently taking rigs out as much as 5,000 metres total measured depth, which requires top drives with basically 50 per cent more torque. Furthermore, he added, companies are almost doubling mud-pump horsepower. Drilling deeper and faster Number of drilling rigs Rig operation days Rig utilization Number of wells drilled Average days per well Metres drilled (000s) Average metres per well Average metres per day Rig revenue/utilization day
Drillers are installing larger top drives, Geddes said, which probably require the same frequency of repair as their smaller counterparts, but because of their size and robustness, they cost a bit more to fi x. Pumps are also becoming larger, and as crews pump out further they are putting more rock through the liners, pistons, valves and other such components, and there are associated repair costs—almost double in some cases. “Drilling companies usually know their costs well, and they have to charge accordingly,” he said. “I don’t think there are any drilling companies going bankrupt, and so they are charging enough to cover their costs.” Mark Salkeld, president and chief executive officer of the Petroleum Services Association of Canada (PSAC), said the costs associated with drilling and completions activity are heavily leaning toward the completions side of the equation, and a significant part of that has to do with horizontal multistage fracs and all the pumping and circulating that goes on with it. “Those are the two areas—the pumps for pumping fracs and the coiled tubing,” he said. “It’s not a problem. It’s just a big expense.” Impacting the wear and tear on completions equipment is longer pumps at higher pressures, as well as the fact that equipment is working with sand as a proppant, Salkeld said. “Because of the environ ment, with respect to what 822 89 we are pumping, it wears 24,39 20,043 out faster. Even if you moved 42% 40% away from water in fracs, 0,753 0,903 .6 which we are trying to do… 20,869 22,733 there is still the sand com,94 2,085 ponent, which is a huge 68 89 $2,030 $22,08 part of it. That is what we Source: Precision Drilling pump down there to hold the
fractures open, and so there would still be that abrasive factor.” Dealing with coiled tubing is another cost associated with completing longer, deeper wells, Salkeld said. “You’re running that coil in and out of that hole. It is a great big circular spool at surface, and then you are spooling it in, straightening that pipe out and then bending it around corners below surface. It has a lot of flex, twisting and torque on it. That gets changed out on a regular basis.” For NCS Energ y Ser v ices, coiled tubing does present challenges as wells get longer and longer said Eric Schmelzl, vice-president of strategic business. “The BHA [bottom hole assembly] per se on the end of coiled tubing produces a running drag, if you will, and so you’re trying to push on a rope, essentially. It’s a rope made of steel, so there is a bit of stiffness, but when it is three miles long it gets pretty flexible in that sort of environment. “We have come up with some methodologies to reduce that running force as much as possible, both by causing less drag on the BHA, but also with some vibration tools we have deployed to convert the static coefficient of friction into a dynamic coefficient of friction, which lowers the force necessary to reach greater depths.” Salkeld said PSAC is currently working with its members and government finance departments to update capital-cost depreciation in the tax regime in order to account for the more rapid rate of equipment depreciation for service companies. “Businesses are allowed a certain amount of depreciation writeoff on equipment, and so what they used to write off on a mud pump 10 years ago or how fast they could write off repairs and maintenance, tax wise, on the fluid end of a mud pump 10 years ago, does not apply today.” OIL & GAS INQUIRER • MARCH 2015
9
In The News
Low prices could spur midstream ownership changes By Elsie Ross
In a lower-priced commodity environment, producers will be forced to think more about whether it’s worth continuing to hang on to their midstream assets, a Keyera executive said at an investment conference in Toronto in January. “I think even in 2014, prior to this correction, you saw the evaluation gap start to widen quite a bit between producer evaluations and midstream evaluations,” said Steven Kroeker, Keyera chief financial officer. He was a presenter at the AltaCorp Capital and ATB Corporate Financial Services annual energy, diversified industries and agri-industries institutional investor conference. At the same time, he acknowledged that in Canada producers like to own their own facilities in contrast to the U.S., where producers are more willing to monetize midstream assets.
“From our point of view, we are more than willing to look at those kinds of assets; the question will really become are they the right assets that fit Keyera,” said Kroeker. “We want to make sure that even in an environment like this we are not going to go buy anything without making sure it fits the strategy rationale for those core areas and areas we want to get into. “But hopefully you would see some producers let go of some assets. We are always trying to get some of our assets up to 100 per cent; it’s tough sometimes to get rid of those last minority interests and let us go to 100 per cent and have the flexibility to run with that asset.” Kroeker said he believes the company “is in a really good spot” for managing the downturn.
Its bigger facilities—R imbey and Strachan—are pretty well full and Brazeau River is getting there, he said. “To have very full facilities in 2014 gives us a very good leg to stand on in 2015.” He noted that the midstream business generally lags in a downturn because once a well is tied in to a facility “it takes a very low netback before you are encouraged to shut it in.” At the same time, Keyera can empathize with producers and the challenges they are facing, said Kroeker. “We are constantly trying to work with producers to work through these situations and see if we can be f lexible and help them out, whether it’s on the NGL [natural gas liquids] side, which is related to oil prices, or slowing down projects a little so it will work up with them.”
Sustainability of shale oil challenged By Elsie Ross
Shale/tight oil production from the Bakken and Eagle Ford plays, which has soared in recent years and now accounts for 62 per cent of current U.S. output, is near its peak and set for a steep decline that will last for years, an oil and gas conference was told in January. “Contributing factors are the high natural decline rates, the recent downturn in drilling as well as prices and the blow up of the high-yield junk bond energy market,” said Bill Powers, an energy analyst and author. “This is profoundly important because to get the payout, getting your drilling investment back for a Bakken well is now 9.5 years at current prices,” he said. “The economics of the wells are really impacted by the course of the prices for the first two years after those wells come online.” Powers was debating Ed Morse, global head of commodities for Citi Research, on the sustainability of shale oil and gas. Morse said it should not be assumed that because some shale oil plays are not currently economic that they will not become profitable again. However, he acknowledged that this is a traumatic year, especially for shale oil. 10
MARCH 2015 • OIL & GAS INQUIRER
The big four U.S. shale plays by the numbers Average well EUR
Average well cost
Average break-even price
Eagle Ford
530,000 boe
$7.2 million
$44.92/boe
Bakken
446,000 boe
$8.5 million
$50.37/boe
5.4 bcfe
$6.6 million
$2.22/mcf
477,000 boe
$6.6 million
$44.65/boe
Play
Marcellus Permian
Source: Hart Energy
“Undoubtedly there will be a shakeout of companies, and undoubtedly there will be a reduction in the rate of growth in production,” he said. In the Bakken/Three Forks in North Dakota, Bakken production is centred around the Nelson Anticline with the most productive wells producing more than 700 bbls/d. “I expect that would peak sometime later this year, given the huge number of rigs that have stopped drilling and the lack of completions in recent months,” Powers said. In Montana, the Bakken Elm Coulee Oil Field, discovered in 2000, is the only field that has been commercially
developed and it is already in decline along with the Bakken in Saskatchewan, he said. Since 2000, the Bakken/Three Forks has produced approximately 1.2 billion barrels of oil and 1.1 tcf of natural gas from 9,200 wells. Although the U.S. Energy Information Administration has estimated it will recover about 8.8 billion barrels of oil, Powers suggested a more realistic estimate of future recovery is 5.1 billion barrels of oil. T he average recover y per well to date is 128,000 barrels and the average well has been on production for three years, the conference heard. Powers estimates the average well will produce
In The News
“Getting your drilling investment back for a Bakken well is now 9.5 years at current prices. The economics of the wells are really impacted by the course of the prices for the first two years after those wells come online.” — Bill Powers, energy analyst and author
250,000 barrels of oil along with 200 mmcf of gas. In the Eagle Ford shale, the majority of the best wells are clustered in a handful of counties. Since 2009, the formation has produced roughly 900 million barrels of oil and about four tcf of gas from 10,500 wells. While Powers maintained that a realistic estimate of future recovery is 4.3 billion barrels, the EIA’s estimate is 10.8 billion barrels.
The average recovery per well to date is 72,000 barrels of oil although the average well is less than three years old. Morse, though, suggested that continued shale activity ultimately should result in improved recovery rates. According to service companies’ research and development, only five per cent of the rocks being exploited are recoverable and the alternate level of reserves that are recognized have a
lot to do with the economics of the technically recoverable resource base, said Morse. “There is no reason why we should not see that five per cent move to 10 per cent to a significantly higher number as the rocks are better understood and industry continues to experiment,” he said. In rebuttal, Powers countered that while there will be great technological advances, he also believes that “geology is going to win.”
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OIL & GAS INQUIRER • MARCH 2015
11
BRITISH COLUMBIA WELL ACTIVITY JAN/14
JAN/15
Wells licensed
23
JAN/14
JAN/15
Wells spudded
8
JAN/14
JAN/15
70
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
B.C. British Columbia
Falling oil prices a second chance for LNG, says AltaGas CFO By Elsie Ross
The turmoil in oil markets over the past six months has enabled Canada to recover from some of the “mistakes” it made such as delays in rolling out an LNG tax and in resolving some First Nations issues, an LNG proponent said. “What people are starting to see is how quickly the energy markets can change on you,” Deborah Stein, senior vice-president of finance and chief financial officer of AltaGas, told a CIBC investment conference in Whistler, B.C. “If you don’t recognize the size of the pie and the complexity of the space and what goes into making these investment decisions, you’ll miss the boat,” she said. “Had it not been for what has gone on in the last four to six months, we may have been in an entirely different position on LNG.” While at one point companies proposing LNG projects were pushing for prices linked to oil, LNG prices have fallen with the decline in oil prices, the conference heard.
$0–$2/mcf AltaGas estimated supply cost to Japanese market
“Asians are actually in the driver’s seat around how they manage their price exposure,” said Stein. “When you look at what’s gone on in the last four to six months, I don’t think anyone is really anxious to jump right in to the LNG contracting game right now. I think people are going to sit back and say what does this look like in the long term.” AltaGas is part of a consortium developing the small-scale Douglas Channel LNG
project, which it acquired in January through a receivership process. The company also is a 50 per cent owner in Triton LNG Limited Partnership with Idemitsu KosanCo., a Japanese refiner. Triton, which has an export licence for a maximum of 2.3 million tonnes per year, is looking at a 2020 start-up, analysts heard. Stein said she thinks it’s critical that companies in the energy infrastructure business have a long-term view of what’s going on in energy as they are making 25to 35-year commitments on capital. “We know what the price is in the basin. We have a pretty good idea, at least for our fi rst-phase project, what the cost of capital looks like. We know what it is going to cost to get it to Asia, and we believe we can get it to the Japanese market for $10–$12/mcf and when you look at the long-term price in Asia, that’s not a bad price.” The Douglas Channel project, which is scheduled to come on stream in 2018, has an off taker for the gas and has a company (EXMAR) that will build the ship, she said. “Now it’s about finalizing the capital cost, fi nalizing the off take arrangements,” she added. Over the past couple of years, AltaGas kept its environmental work up, along with First Nations consultation. “Now we can ramp up and start looking at what that project looks like, and we will start discussions with the offtaker,” said Stein. T he recent a n nou ncement f rom ExxonMobil Canada that it has filed an application to the B.C. environmental and assessment office for an LNG terminal bodes very well for the Canadian basin, she said, noting that the company was looking at the 2021-23 time frame.
West Coast LNG project proposals Project
Capacity (bcf/d)
Kitimat LNG
.4
BC LNG Export Co-op
0.25
LNG Canada
3.2
Pacific NorthWest LNG
2
Aurora LNG
not released
Prince Rupert LNG
3
Triton LNG
0.3
ExxonMobil/ Imperial Oil
4
Woodfibre LNG
0.3
Woodside LNG
.8
WesPac LNG
0.4
Steelhead LNG
4
Discovery LNG
2.6 Source: CAPP
With no shortage of LNG globally in the short term, companies are now looking at the next phase of LNG developments and of ways to get that supply-demand balance back into equilibrium, said Stein. “I think the 2021-22 time frame is now kind of starting to be the right sweet spot for how these projects all unfold,” she said. Canadian West Coast LNG offers a longterm supply underpinned by a strong basin and a stable government where the export licence isn’t going to be pulled as soon as there is trouble, she said. Canada also has a competitive advantage off the West Coast in terms of the ambient temperature of the gas to get it into Asia and the shipping times to Asia, she said. AltaGas already has a customer for its first phase and is now in a position to move forward with work on the Triton project announced in January 2013. OIL & GAS INQUIRER • MARCH 2015
13
British Columbia
Chevron slows LNG spending By Richard Macedo
Chevron Corporation is “significantly pacing” its spending on the Kitimat LNG project due to current market conditions. Responding to a question on whether he is seeing a change in LNG pricing for existing or future projects, given the drop in oil prices (as LNG prices are typically linked to oil), John Watson, chairman and chief executive officer said, “The trend has been a very fluid environment and, frankly, there’s been a lot of pressure on LNG pricing both in response to immediate conditions and [in] response to the projects that have gone to a fi nal investment decision around the world, so there is pressure on LNG markets. “Notwithstanding that, we did sign a contract during this period that’s an oillinked contract with a reputable company for a medium-term slice of volume toward the end of the decade, which gets us up into the range where we feel pretty good about the projects Gorgon and Wheatstone where we’ll basically be at our target for sales—we’ll be between
Chevron will be drilling fewer wells in the Horn River and Liard basins this year.
75 and 80 per cent on Gorgon and 85 per cent for Wheatstone [Australian projects], so we feel in pretty good shape. We obviously need good contracts that underpin new developments. So, one of the projects that we’re pacing until we can see conditions that’ll support a project is at Kitimat, [B.C.], in Canada. We’re continuing with some of the work we have u nder way to del i neate t he resource and reach agreements w ith First Nations people and permitting and things of that sort. “But,” Watson adds, “we’re significantly pacing the spend of that project, and we’ll get alignment on it, and have good a lig n ment i n ea rly days w it h Woodside Petroleum Limited, which has replaced Apache Cor poration. Other than that, I think people are pretty cautious right now in the LNG market. Our view is it’s not clear that all the greenfield projects that are being contemplated can meet economic hurdles at some of the prices we’re seeing.”
Murphy suspends Montney drilling By Elsie Ross
As part of its capital spending cuts across the company, Murphy Oil said it planned by mid-February to drop all three rigs currently drilling for natural gas at Tupper in northeastern B.C. The company is also shutting in uneconomic heavy oil wells at Seal in the Peace River oilsands and is beginning to see production declines, Roger Jenkins, president and chief executive officer, said in a conference call to discuss 2014 fourth-quarter and year results. About 250 bbls/d of production currently is shut in at Seal and “at the worst case 80 wells would be shut in for a couple of thousand barrels a day for the year,” he said. Murphy is looking at each well’s economics to operating expenses on an individual well basis, said Jenkins. “We’re not probably going to shut in the whole field.” 14
MARCH 2015 • OIL & GAS INQUIRER
86 mmcf/d Murphy’s Tupper gas production in the final quarter of 2014
At Tupper, Montney gas production averaged 186 mmcf/d in the fourth quarter, up from 146 mmcf/d in the third quarter, as the company brought eight new wells on stream. Another nine wells are to come on this year. Forecast fi rst-quarter 2015 production is 176 mmcf/d, but that is expected to decline throughout the year for an average of 170 mmcf/d in 2015, analysts heard. “We have seen excellent results using our new completion and choke management strategies, which should lead to improved EUR [estimated ultimate recovery] on future wells,” said Jenkins. The company has 65 mmcf/d of gas hedged at C$4.13/mcf at AECO for 2015, he said. Murphy’s Canadian revenues in the fourth quarter were $236.7 million, including $88.5 million from its Syncrude Canada
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interest, compared to $250.7 million in the fourth quarter of 2013. Total Canadian revenue for the year was $1.04 billion ($391.1 million synthetic crude), down from $1.15 billion ($441.3 million synthetic) a year earlier. Canadian exploration expenses for the quarter and year declined to $5.2 million and $21.1 million respectively from $5.7 million and $53.8 million in 2013. Total exploration and production capital expenditures for Canada rose to $130.6 million in the fourth quarter of 2014 from $51.7 million a year prior, while full-year exploration and production capital expenditures rose to $447.6 million in 2014 from $367.3 million in 2013. Canadian production in the fourth quarter averaged 63,167 net boe/d (58,184 boe/d in 2013), while total production for the 12 months averaged 54,318 boe/d, down from 60,473 boe/d in 2013.
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NORTHWESTERN ALBERTA WELL ACTIVITY JAN/14
JAN/15
Wells licensed
34
JAN/14
JAN/15
Wells spudded
28
JAN/14
JAN/15
95
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Birchcliff looking for balance with service companies to help them survive tough times By Richard Macedo
The plunge in oil prices has producers looking for cost savings from service providers, but Jeff Tonkin, president and chief executive officer of Peace River Arch gas producer Birchcliff Energy, said that while he’s looking for reductions, he’s not looking to drive service companies “straight into the ground.” Tonken told the CIBC institutional investor conference in January that the company has flexibility in terms of where and how it spends its money. “There’s no doubt that we’re re-bidding all of the services that are provided to Birchcliff,” he said. “Our goal is not to drive our service providers straight into the ground. Our goal is to see if we can get our service costs reduced. “At the same time, we have a lot of what we would call positive relationships with people,” Tonken added. “We’ll look for reductions on one side, and on the fl ip
side then we’ll continue to use them, which is a benefit for them because a lot of people are being laid off. On the fl ip side, when things get really heated up, we expect that we’ll get more reasonable costs from them because we were there to support them when things were tough.” Current tough times for the service sector are only going to get worse as battered exploration and production companies are not only seeking cost reductions, they are demanding them. The Canadian Association of Oilwell Drilling Contractors issued an updated drilling activity forecast in late January—which shows a total of 6,612 wells completed in 2015, off from the actual total of 11,534 wells completed last year—reflecting the significant changes in commodity prices since the summer of 2014. Sadiq Lalani, chief financial officer with Kelt Exploration, told the conference that,
with respect to rigs, the company doesn’t enter into long-term contracts. “We’ve got really good relationships with drilling companies who we’ve been using for the past 20 years in different companies,” he said. “Right now, the rig rates on doubles that we’re looking at are probably about 15 per cent lower than they would have been six months ago. “What you usually see is, you see rig rates go up at this time of the year because drilling is the busiest in that December-toMarch period, and we haven’t seen rates go up, so we’re still looking at about 15 per cent savings on our rig rates,” he said. As far as pressure pumpers go, the company hasn’t yet seen large discounts. “I think there’s a lot of activity on the completions side in the winter, but I think savings will come probably in the spring— spring/summer,” Lalani said.
NuVista cuts capital budget, divests non-core assets Montney producer NuVista Energy said that it is reducing and high grading its 2015 capital spending plan to a range of $270 million to $290 million in order to maintain financial strength during the current commodity price weakness. To further improve its financial flexibilit y, the company has divested certain non-core assets in the W5 operating area for gross proceeds before adjustment s of $16.8 m i l l ion. T he asset s, which were sold late in the fourth quarter of 2014, included approximately four mmcf/d of natural gas production and
5,000 boe/d
NuVista Wapiti Montney production in the final quarter of 2014
100 bbls/d of natural gas liquids for a total of 750 boe/d. The revised capital budget has been reduced from the initial budget of $340 million to $380 million announced in late October.
Spending for the fi rst half of 2015 will be approximately 50 per cent to 60 per cent of the annual total. NuVista said it is making the adjustments immediately and will hold that pace of spending until early in the second quarter of 2015 when it will be re-evaluated upon entering the spring breakup period. The company said it has a high level of flexibility to further adjust the remaining 2015 capital spending plan in order to maintain balance sheet strength and maximize value in line with market conditions at that time. OIL & GAS INQUIRER • MARCH 2015
17
Northwestern Alberta
NuVista Montney new well IP results Location Bilbo Development Type Curve Well 22 - Bilbo Dev. 00/07-06-066-05W6/00 Well 23 - Bilbo Dev. 00/08-06-066-05W6/00 Well 24 - Bilbo Dev. 00/04-27-065-05W6/02 Well 25 - Bilbo Dev. 00/4-34-065-06W6/00 Well 26 - Bilbo Dev. 00/6-33-065-06W6/00 Well 27 - Bilbo Dev. 00/04-02-066-06W6/00 Well 28 - Bilbo Dev. 00/05-02-066-06W6/00 Montney Delineation Type Curve Well 29 - North Montney Delineation 00/05-24-068-09W6/00
Raw gas Condensate Total sales (mmcf/d) (bbls/d) (boe/d)
CGR (condensate/ raw gas (bbls/mmcf)
.
,
4.3
405
,077
93
4.6
72
,379
56
7.8
6
,760
78
4.9
33
,087
67
4.2
268
96
64
8.3
52
,740
6
7.9
578
,770
74
.
,
9.0
236
,694
26
Source: NuVista Energy
18
MARCH 2015 • OIL & GAS INQUIRER
Field operations have been strong and steady through the fourth quarter of 2014, with all key operational targets being met, the company said. NuVista has reached production in excess of 15,000 boe/d in the Wapiti Montney area, and additional wells continue to be tied in for start-up through the first quarter of 2015. Based on field estimates, total production for the fourth quarter of 2014 is expected to be at the higher end of NuVista’s guidance range of 21,000–22,500 boe/d, with annual production for 2014 expected in the higher end of the guidance range of 17,750–18,500 boe/d. NuVista said its hedge position has never been stronger, with 53 per cent of its oil and condensate production hedged at a floor price of C$95.82/bbl WTI and 60 per cent of its natural gas production hedged at a f loor price of $3.88/mcf (both net of royalties). The company continues to have production hedged into 2017 at similar prices but w it h tapering volumes.
Northwestern Alberta
Monobore designs, acid fracs, may be key to Slave Point, says Penn West Penn West Petroleum hasn’t quite “cracked the code” for optimum Slave Point wells, but monobore designs using single casing strings have helped reduce times to about 14 days from 24, said president Dave Roberts. Before oil prices hit the skids, Penn West was a major driller in the potentially lucrative light oil play in the deep expensive Slave Point carbonate formation of north-central Alberta. Last year, the company continued to test various drilling and completion techniques in the Slave Point as it focused on optimizing production performance, recoveries, cycle times and per-well costs. However, Penn West isn’t drilling Slave Point wells this year “because they don’t make the cut, in my view,” at oil prices of less than C$70/bbl, Roberts told last week’s CIBC investor conference in Whistler, B.C. Instead, the company is focusing its 2015 spending on its other two core plays—the Cardium and the Viking.
Slave Point potential recovery factors (oil/section ,s barrels) Field
Sawn Lake
Otter
Evi
Loon
Red Earth
Senex
Nipsi
0.3–0.5
0.4–0 .6 0.8–.2
Recovery factor %
0.3–0.6
0.3–0.6
10%
0.5–.2
15%
0.8–.8
20%
.0–2.4
0.3–0.5
0.3–0.5
0.2–0.4
0.5–.2
0.5–.0
0.3–0.8
0.4–0.7
0.6–.0
0.8–.8
0.8–.5
0.8–.2
0.6–.
0.9–.5
.2–.8
.0–2.4
.0–2.0
.0–.6
0.8–.4
.2–2.0
.6–2.4
Source: AltaCorp Capital
Crucial to cutting costs in resource plays is figuring out a cookie-cutter approach to well designs that achieves manufacturing-style efficiency. “In the Cardium in general, we would say nine out of 10 wells we drill are formulaic,” Roberts said. But in the Slave Point, the company is still doing a lot of experimenting. “We drilled 24 wells and used 14 different completions setups last year. Because we don’t have any competition there, we were
having to try a variety of different things,” Roberts said. “And I think we’ve landed on, generally, in my view, monobore designs where we think we can get away with it. And it looks to us like a return to old-school acid fracs is going to be the answer. When we’ve done wells correctly using that setup, we’ve dropped costs from $6.5 million to $4.5 million. And if you could drill wells out there for those numbers, then that play will work.”
OIL & GAS INQUIRER • MARCH 2015
19
NORTHEASTERN ALBERTA WELL ACTIVITY JAN/14
JAN/15
Wells licensed
0
JAN/14
JAN/15
Wells spudded
6
JAN/14
JAN/15
6
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
Low prices forcing oilsands efficiencies By Lynda Harrison
Photo: Joey Podlubny
Oilsands companies are handling low oil prices in a variety of ways: some are cutting spending via layoffs, some are slowing project construction and some are drilling fewer wells. But those at a recent investor conference agreed: it’s a good time to tackle cost efficiency. “The silver lining in this whole dark cloud of prices is that there will be efficiencies that are driven into the business. You will have reductions in cost; your cost efficiencies will go up,” said John Brannan, executive vice-president and chief operating officer of Cenovus Energy Inc. Companies have inefficiencies in an environment of $100 oil but at $50 oil, there is an urgency to cut those inefficiencies out of the organization, said Brannan. Cenovus is analyzing individual commodities, chemical costs, all its operator costs and the overtime it pays with a finertooth comb than it did before, Brannan told the CIBC 18th A nnual W histler Institutional Investor Conference. Supply costs are declining, Brannan added.
With less work to go around, vendors are reducing their prices to retain their per cent of market share and Cenovus is working with them in an attempt to build long-term relationships, striving to avoid a situation in which vendors slash their prices now only to hike them again when oil prices recover. Oilsands operators at the conference also agreed prices will stay low for some time and may even drop before they rise again, analysts heard. “We think that we’re probably in for a longer period of time of low oil prices before it starts to recover,” said Brannan. “Production in the U.S., even though you’re seeing the rigs slow down in the Eagle Ford and Permian Basin and others—the wells that are already drilled and are being completed and brought on—I think the general consensus is that production will still increase through 2015 before, maybe, towards the end of ’15, it will start to tail off.” Brannan said he’s been in the industry for 35 years and this is the fifth or sixth time he’s experienced similar price drops.
All costs are on the table at oilsands developments with prices averaging less than $50/bbl.
Innovation and cost containment will prevail, higher prices will eventually return and industry will be robust once more, he said. W h i l e Su n c or E n e r g y r e c e nt l y announced it will cut about 1,000 jobs and $1 billion from its planned spending this year because of low oil prices, despite its $2.4-billion budget cut, Canadian Natural Resources (CNRL) is not considering layoffs, the conference heard. “Currently, today, we don’t consider we do need to do layoffs,” said Corey Bieber, CNRL’s senior vice-president of finance and chief financial officer. “We don’t tend to have a lot of excess personnel running around.” If the company has a temporary need for additional workers, it tends to use contractors so its message to employees has been “‘Don’t look over your shoulder; just do your job and be effective and efficient, and the rest will take care of itself,’” he said. CNRL recently announced it will cut planned 2015 spending by $2.41 billion to $6.19 billion from the $8.6-billion budget released last fall. CNRL has said it will defer spending of $470 million on its Kirby North Phase 1 SAGD project until oil prices improve. It is planning to spend only $105 million on the project this year, down from $575 million in the original budget. However, the company continues to invest in its oilsands mine, Horizon, where costs continue to be less than estimated, said Bieber. “Because the activity is so specialized, there has been less cost inflation in the last couple of years, and we continue to be pleasantly surprised in terms of both theproductivity and the cost estimates that OIL & GAS INQUIRER • MARCH 2015
21
Northeastern Alberta
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MARCH 2015 • OIL & GAS INQUIRER
are coming back on the work packages that we let,” he said. T he Horizon expansion will add 125,000 bbls/d of production capacity— 45,000 bbls/d in late 2016 and 80,000 bbls/d in late 2017. However, expansion won’t go ahead at any cost, he added. The company has broken down the project into 130-some work packages, with each package having the three elements of engineering, procurement and construction. “That’s a lot of little levers that you can pull and some elements could get accelerated, some could be slowed down,” said Bieber, adding much of that depends on the bids it receives. Bieber agreed the current low-price environment is a good time for the company to work with its suppliers, contractors and its own employees to cut costs and be more efficient. “I think we have to take advantage of that and make sure we do that to make this a sustainable industry through the cycle,” said Bieber. “This is an opportunit y for us to maybe upgrade some talent, get the right people doing the right jobs but also make sure we have proper supervision in whatever contractors are doing work for us, and supervision makes an incredible difference in terms of the effectiveness and efficiency of the work crews.” Alister Cowan, Suncor Energy’s executive vice-president and chief financial officer, said this low-oil-price environment is precisely the time to build a major, capitalintensive project such as its Fort Hills mine— “when no one else is building.” One reason is that it now has access to the best-quality contractors available, he said. “We’re already seeing up in Fort McMurray whereby we’ve got contractors we would have liked to have had at Fort Hills coming to us now, saying, ‘Can we work on your project?’” Suncor has been able to tell existing contractors that if their performance and productivity have not met expectations, they will be replaced by better ones at a lower rate, he said. The other reason is that good, experienced tradespeople such as electricians, pipefitters and construction workers are now available, and Suncor is seeing a
Northeastern Alberta
big increase in productivity as a result, Cowan added. He said Fort Hills’ construction manpower is currently around 3,000 and is scheduled to peak at about 6,000 workers. First oil is slated for 2017, with ramp up to full production of about 180,000 bbls/d set for 2018. Cowan said it would cost too much time and money to stop building Fort Hills in the middle of its construction period, put it into “safe mode”—as it did with its in situ oilsands projects Firebag 3 and Firebag 4 and the now-scuttled Voyageur upgrader—and then start up again. “We’ve been there before at Suncor, we know what it cost us; it’s multi-hundreds of millions of dollars. We’re not going to go there again.” The company won’t cancel the project but would slow it down if oil prices remained this low for two to three years, said Cowan. Fort Hills is expected to have a 50-year life. Suncor does not make decisions on such projects based on the spot price of oil, and it expects multiple periods of price volatility during its lifetime, said Cowan. He said Suncor believes the price of oil will return to the $90–100-bbl range in the long term, probably in three or four years, when Horizon and the offshore Hebron oil project are scheduled to come on stream, but short-term, oil will experience much more volatility. Suncor, the operator, has 40.8 per cent ownership in Fort Hills, Total E&P Canada has 39.2 per cent and Teck Resources Limited has 20 per cent.
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Syncrude provides expansion costs, workforce estimates If approved, pre-production capital expenditures are estimated at $3 billion over the nine-year construction phase, from 2018 to 2026, for both the east and west pits where Syncrude Canada has applied to expand its mining operations. Syncrude has applied to the Alberta Energy Regulator for the Mildred Lake OIL & GAS INQUIRER • MARCH 2015
23
Northeastern Alberta
Syncrude estimates that up to 80 per cent of the pre-production expenditures will be spent in Alberta and 20 per cent elsewhere in Canada.
extension project (MLX project), to enable sustained bitumen production in two additional nearby areas once the currently approved areas have been depleted. The MLX–W pit will be phased in over four years, starting in 2023. On depletion of the North Mine in 2026, the MLX–E pit will be opened up to supplement MLX–W production, maintaining bitumen production rates from Mildred Lake at 184,000 bbls/d. Will Gibson, spokesman, said the new areas, if approved, would comprise 38 per cent of Syncrude’s existing, approved footprint. According to its application, Syncrude estimates that up to 80 per cent of the pre-production expenditures will be spent in Alberta and 20 per cent elsewhere in Canada. The average size of the pre-production workforce is estimated to be 1,159 workers.
Given experience and current operations in the socio-economic study area (SESA), Syncrude anticipates that up to 40 per cent of the pre-production workforce will be existing residents in Fort McMurray and Fort MacKay, Alta., and the remaining 60 per cent will be new hires. The duration of the mining operations phase will be 42 years, from 2023 to 2064; this includes mining operations from 2023 to 2036 and fi nes management activities from 2030 to 2064. The average size of the operations workforce will be about 670 annually. Up to 83 per cent of the operations workforce will be transferred from existing mining operations at the North Mine and the remaining 17 per cent will be new hires. Average operations expenditures are estimated at $343 million annually. All
operations expenditures are to be spent in Alberta. Syncrude anticipates that 60 per cent of the pre-production workforce will live in the camp, 30 per cent in Fort McMurray and 10 per cent in Fort MacKay. During operations, based on its current experience, Syncrude expects that the majority of the operations workforce will live in the SESA and less than five per cent in the camp. Syncrude intends to use the Mildred Lake Village (MLV) permanent camp to accommodate pre-production and operations workers. The MLV is adjacent to the Syncrude Mildred Lake site. It has a capacity to house up to 2,000 workers. Although it is open to different developers in the area, its first priority is to accommodate Syncrude workers.
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CENTRAL ALBERTA WELL ACTIVITY JAN/14
JAN/15
Wells licensed
87
JAN/14
JAN/15
Wells spudded
8
JAN/14
JAN/15
88
Rigs released
C.A.B.
▼
▼
Central Alberta
▼
Source: Daily Oil Bulletin
Trilogy will “turn engine off” until prices rebound By James Mahoney
For Trilogy Energy, the drop from last year’s $440 million capital budget to this year’s $100-million figure was swift but if its partners were amenable, it would cut spending further still, the company’s president said. “Our message isn’t very sexy,” John Williams, chief operating officer, told CIBC’s institutional investor conference in Whistler, B.C. “But at the end of the day, we just can’t drill oil and gas wells profitably in this environment, so we’re going to try not to do that. Rather than just drill and hope for better commodity prices, we’re just going to turn the engine off and wait until we see better commodity prices.” The company, however, still has a limited drilling program. “In this environment, we’re trying to do as little as possible,” Williams said. “We’re trying to preserve our balance sheet and our opportunity set, so we can cultivate them in a higher commodity price environment later. “We don’t think it’s prudent to spend anything. The $100 million in capital we’re spending is basically to participate in joint interest operations with our partners.” After posting average production of 35,100 boe/d in 2014, Trilogy expects to see volumes average 30,000 boe/d this year, a drop of roughly 14 per cent. At the same time, Trilogy would be prepared to boost spending to $300 million, $400 million or even $500 million if
Trilogy Kaybob Montney oil pool development profile Field
(estimate)
Total
Wells drilled
22
24
3
30
07
Well costs ($ millions)
98
09
33
20
460
Infrastructure costs ($ millions)
33
5
33
5
36
Land costs ($ millions) Total capital ($ millions) Production (boe/d) Operating income ($ millions)
36
-
-
-
36
67
60
66
39
632
2,446
9,829
,653
2,000
-
54
72
99
80
605
Source: Trilogy Energy
and when the time is right, but with oil and gas prices where they are, Williams made it clear the time is not right. Like other producers, Trilogy is expecting oilfield service rates to fall and plans to wait for that to happen before advancing some plays. “Quite honestly, not a lot of these plays make money at these commodity prices.” Current capital spending plans are based on projected 2015 cash flow. Trilogy has signalled an interest in taking on a joint venture partner to develop its Duvernay shale assets, but Williams made it clear the company is in no rush to do so, given current oil prices. “Quite honestly, we’re not going to race out there and do something unless it makes sense.… We don’t have any preconceived ideas of what a Duvernay joint venture
might look like. We might coin the term: it’s a cattle call for the Duvernay.” Williams’ preferred plan is to begin the joint venture process now, finishing it in a higher commodity price environment. Trilogy estimates that roughly 125 net sections are in the oil window of the play and roughly 75 net sections are in the natural gas condensate window of the Duvernay play. The company’s debt is currently about $750 million. Williams told the conference that Trilogy expects to see an issue with its debt covenants in this year’s fourth quarter. “We’ve talked to the majority of our banking syndicate and lenders, and they are fairly supportive of relaxing those covenants,” he said. Trilogy expects the banks to conduct a review in late March 2015.
Tamarack sets budget at $47 million Tamarack Valley Energy has unveiled an initial 2015 capital budget of $47 million with only $10.5 million allocated for the first half of the year. That compares with an initial 2014 budget of $63.5 million, which was increased to $116.4 million.
Tamarack said it focuses on drilling wells with a payout of 1.5 years or less, but those opportunities have been drastically reduced at current commodity prices and service costs. Therefore, Tamarack plans to keep 2015 spending within cash flow and will
pay down debt during the fi rst half of the year, adjusting its budget to match changes in commodity prices as the year progresses. The 2015 budget is based on average price assumptions of US$50/bbl (US$46/bbl in the fi rst quarter and US$54/bbl in the fourth quarter), an Edmonton Par price OIL & GAS INQUIRER • MARCH 2015
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MARCH 2015 • OIL & GAS INQUIRER
Spending in the Cardium continues to be cut as companies deal with new market realities.
of $51.60/bbl, an AECO gas price of $2.65/GJ and an 85-cent Canadian dollar. Production is estimated to average 8,000 boe/d in the first quarter with a 60 per cent weighting to oil and natural gas liquids. The forecast excludes behind-pipe volumes of about 1,200 boe/d plus 435 boe/d shut-in for economic reasons. Based on current strip pricing, the company expects to reduce net debt to about $116 million to $118 million by the end of the second quarter. Tamarack drilled two net Cardium horizontal oil wells at Wilson Creek in early January, bringing the total to three net Cardium horizontal oil wells drilled and awaiting fracturing. But because of low prices, these wells have been shut in. Also, an Alder Flats well has been shut in since the third quarter of 2014 due to facility constraints. When economic conditions improve, the behind-pipe and shut-in volumes will allow Tamarack to ramp up production. The estimated 1,200 boe/d behind-pipe is in the Wilson Creek/Alder Flats area. The company plans to use this period of reduced drilling activity to continue its ongoing initiative to reduce costs further and improve capital efficiencies.
Photo: Joey Podlubny
FAST
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Central Alberta
Velvet Energy raises $100 million Velvet Energy has obtained an incremental $100-million equity line led by its private equity investors Warburg Pincus, Trilantic Capital Partners and ZAM Ventures, the company announced in January. Velvet Energy said it uses advanced drilling and completion technologies to explore for and develop oil and gas assets within established plays in west-central Alberta. It is currently producing approximately 14,000 boe/d from its footprint in the Edson, Alta., area, where it is achieving superior field-level economics. This incremental equity line will enable the company to build on its success to date, through the pursuit of acquisitions, additional growth and corporate development opportunities, the company said. “Velvet Energy is operationally and financially well positioned with a high-quality asset base, strong balance sheet, and three sophisticated and supportive investors, led by Warburg Pincus,” said Ken Woolner, president and chief executive offi cer of Velvet Energy. “The access to significant capital resources allows Velvet Energy to take advantage of the current market conditions to continue to efficiently grow its production base and its opportunity set.” This commitment follows an initial equity line totalling $336 million that has been fully deployed by Velvet Energy.
Bonterra chops spending Given the current extreme market volatility and based on current commodity price assumptions, Bonterra Energy says that capital expenditures for 2015 are currently budgeted to be approximately $58 million compared to the 2014 capital budget of $140 million. Bonterra said its fi rst-quarter 2015 budget, of approximately $20 million, will see capital primarily directed to complete and bring on production nine (7.4 net) wells, including six wells that were pre-drilled in late 2014 and three wells that were drilled early in 2015. At the end of the fi rst quarter of 2015, the company will have an inventory of eight drilled wells, all of which can be completed as commodity prices and project economics warrant. Bonterra said it would continue to thoroughly review all expenditure areas, including capital expenditures, operating costs, and general and administration costs. Operationally, Bonterra said it is very pleased with its recent performance, including achieving 2014 average production volumes of approximately 13,100 boe/d, which exceeded the 2014 forecast annual guidance of 12,400–12,700 boe/d. “The company will continue to assess its results on a quarterly basis and will adjust its capital expenditures, dividends and overall operations in accordance with future commodity prices,” Bonterra said in a press release.
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Central Alberta
Bonavista production climbs in 2014 Bonavista Energy said its strategy to concentrate development spending in its core areas led to record production and low cost-reserve additions in 2014. Average daily production for the year rose five per cent to 77,211 boe/d. Volumes rose 14 per cent in the fourth quarter to 85,810 boe/d while year-end exit production was up 17 per cent to 88,083 boe/d. Bonavista put $535.8 million into capital spending in 2014. Based on an independent reserves report, Bonavista added 56 million boe of provedplus-probable reserves during the year, bringing total year-end 2014 working interest reserves to 427 million boe, a seven per cent rise over year-end 2013 figures, management said, noting the company replaced 200 per cent of annual 2014 production. Bonavista reported a 7.6 per cent increase in proved oil and gas reserves during the year, while proved producing reserve additions were 50 million boe, replacing 175 per cent of 2014 production, management said.
Working interest reserves included 1.69 tcf of proved-plus-probable natural gas reserves (1.09 tcf proved), 30.44 million barrels of light and heavy oil (21.37 million barrels proved) and 114.68 million barrels of natural gas liquids (71.96 million barrels proved).
77,2 boe/d Bonavista’s average daily production in 2014
On the cost side, the company cut its finding, development and acquisition costs by 10 per cent in 2014, to $9.95/boe on a proved-plus-probable basis, including changes in future development costs (FDC).
A lso based on the GL J Petroleum Consultants report, Bonavista reported hav ing cut finding and development costs nine per cent to $10.84/boe on a proved-plus-probable basis, including changes in FDC. Management said the company added production efficiently in 2014 at a cost of about $17,000/boe/d on a trailing, 12-month, full-cycle basis. GLJ evaluated 90 per cent of Bonavista’s reserves (on a net-present value, discounted 10 per cent), while the balance of reserves were evaluated internally and reviewed by GLJ in a report dated Feb. 3, 2015, but effective Dec. 31, 2014. In 2014, Bonav ista’s reser ve l i fe index (RLI) did not change materially, management said. For the company ’s total proved reserves, the RLI rose to 9.4 in 2014 from 9.1 years reported in 2013. For proved-plus-probable reserves, the index fell slightly to 13.1 from 13.2 years in 2013.
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MARCH 2015 • OIL & GAS INQUIRER
SOUTHERN ALBERTA WELL ACTIVITY JAN/14
JAN/15
Wells licensed
5
JAN/14
JAN/15
Wells spudded
55
JAN/14
JAN/15
56
Rigs released
S.A.B.
▼
▼
Southern Alberta
▼
Source: Daily Oil Bulletin
DeeThree plans 29 wells this year DeeThree Exploration will spend $160 million in its 2015 capital budget, targeting approximately 13,300 boe/d average production for the year, which represents an 18 per cent increase over 2014 production, the company announced Tuesday. Structured to maintain DeeThree’s strong balance sheet position and to provide maximum fi nancial and operational flexibility, the 2015 budget will see drilling of 13 wells and incurred capital expenditures of about $68 million over the fi rst half of the year. For the latter half of 2015, the company intends to spend $92 million to drill 16 wells. By comparison, in 2014 the company had estimated capital expenditures of $290 million to $295 million, which resulted in DeeThree achieving its exit guidance of 13,000 boe/d in the month of December and averaging 12,700 boe/d production for the fourth quarter. Throughout 2014, DeeThree invested significant capital in upgrades and expansions of its facilities in both of its core areas to accommodate future growth. As a result, about 93 per cent of the company’s 2015 capital budget is directed towards drilling and well completions. The company’s 2015 drilling program is focused on the further development of two core properties with 23 net wells targeting the Brazeau-Belly River and six net wells targeting the Alberta Bakken. An estimated $55-million cash flow based on US$50/bbl WTI oil prices and a low Canadian dollar offsets DeeThree’s spending for the first half of the year, management said. For the whole year, the company is basing its capital budget on oil prices averaging US$60/bbl WTI. DeeThree has 2,000 bbls/d of oil hedged for the year, including 1,500 bbls/d swapped at C$99.20 WTI and 500 bbls/d
DeeThree recent Belly River well performance Well Completion IP IP IP Current number date (204) (boe/d) (boe/d) (boe/d) (boe/d)
Jan 24
Feb 2
205
97
83
75
Feb
528
383
364
220
Feb 20
,083
804
693
232
586
57
46
33
Feb 25
645
444
396
75
Feb 22
85
69
523
59
Mar 9
403
350
328
284
Mar 2
,257
920
70
83
Mar 24
968
80
690
358
Jun 5
365
279
248
47
May 0
950
742
629
294
Jun 29
666
524
433
35
Jul 7
692
634
538
525
Jul 23
275
227
n/a
93
Aug 3
878
886
n/a
,65
Aug 6
973
88
n/a
646
Aug 30
,249
n/a
n/a
63
Note: Based on production days. Source: DeeThree Exploration
hedged with a costless collar US$85 WTI/ US$100.80 WTI. According to management, DeeThree will continue to re-evaluate its capital budget to ensure spending levels are appropriate in the context of prevailing commodity prices. The company maintains a high degree of operational flexibility due to its strong balance sheet and quality of its two core properties. Since the installation of a built-forpurpose gas reinjection compressor in September, DeeT hree has increased re injection volumes for its 100 per cent owned Alberta Bakken assets, and currently 70 per cent of the total gas produced from the pool is reinjected through three injectors. Management said the results of
its expanded gas reinjection enhanced oil recovery (EOR) scheme is consistent with results of the pilot project in improving production declines. DeeThree intends to implement a full-scale gas reinjection EOR scheme for its Alberta Bakken pool in order to more fully exploit the large oil-in-place with an increased recovery factor. With significant investments to date, the company is reportedly well positioned to rapidly increase voidage replacement in the pool with minimal future net capital. Management will commission a fourth injector by the end of March, as well as a fi fth in the third quarter. By the end of the year, DeeThree expects reinjection of 100 per cent of its produced Bakken gas with currently installed reinjection facilities capacity. Furthermore, the company recently implemented a single injector waterflood pilot to complement the gas reinjection EOR scheme. Management is encouraged by results to date, and DeeThree will continue to monitor effectiveness. The company will maintain its enhanced recovery scheme as an integral part of pool development with future drilling activity being closely matched with voidage replacement. At Brazeau-Belly River, DeeThree is demonstrating the depth in its drilling inventory and repeatability of results, management said, as the company’s first well completed this year—04-27-046-15W5—tested at a final rate of about 960 bbls/d of oil. The company has an identified drilling inventory now totalling in excess of 440 locations over a high-working-interest, contiguous land base supported by infrastructure. Management believes the company is well positioned to generate and sustain production growth in the property despite lower commodity prices. OIL & GAS INQUIRER • MARCH 2015
29
Southern Alberta
Zargon encouraged by ASP data Zargon Oil & Gas exceeded its guidance level of 4,100 bbls/d in the final quarter of 2014, averaging 4,150 bbls/d of oil and liquids production in the quarter, while natural gas production averaged 6.43 mmcf/d to essentially match guidance levels of 6.5 mmcf/d. According to management, the drilling of three Williston Basin wells located at Steelman, Sask., and Mackobee Coulee, N.D., as well as two Alberta Plains South wells at Taber, Alta., positively impacted results. However, the mid-December sale of the Hamilton Lake property, which produced about 400 boe/d for the company, reduced production volumes. In early 2014, Zargon announced commissioning and injection into the partially depleted Little Bow Mannville I pool to recover substantial incremental oil reserves as part of its Little Bow Alkaline Surfactant Polymer (ASP) EOR project. To date, crews have injected three million barrels of ASP solution into the fi rst phase of the $50-million project. This
400 bbls/d Zargon projected average ASP production in 2015 injection volume is equal to about 10 per cent of the targeted reservoir pore volume and represents 14 per cent of the total chemical bank (ASP and polymer only) that management has scheduled for the first phase of operation injections. With continued injection and production data encouragement for the ASP project, management has increased current first-phase production volumes to about 280 bbls/d, which exceeds the pre-ASP waterflood baseline rate of 250 bbls/d. Zargon forecasts ASP production to ramp up in 2015 by producing 100, 250, 500 and 750 bbls/d in the successive quarters for the year with an average rate of 400 bbls/d.
Encana completes coalbed methane sale Encana has completed the previously announced sale of certain Clearwater assets in Alberta to Ember Resources for a purchase price of approximately $605 million. The sale includes about 1.2 million net acres of land, over 6,800 producing wells and approximately 180 mmcf/d of natural gas production. “We enter 2015 focused on furthering our strategy and protecting our balance sheet with plans to not add any incremental debt through the year,” said Sherri Brillon, Encana’s chief financial officer. “With the closure of this sale, along with expected proceeds from our recently announced Montney midstream agreement, we continue to competitively position ourselves to thrive throughout the commodity price cycle.” Encana retains approximately 1.1 million net acres in Clearwater, including approximately 480,000 net acres along the eastern edge of the Horseshoe Canyon Fairway.
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MARCH 2015 • OIL & GAS INQUIRER
16
th
biennial
SASKATCHEWAN WELL ACTIVITY XXX/12 JAN/14
XXX/13 JAN/15
Wells licensed
2 255
XXX/12 JAN/14
XXX/13 JAN/15
Wells spudded
49 305
XXX/12 JAN/14
XXX/13 JAN/15
48 278
Rigs released
▼
▲ ▼
▲ ▼
Source: Daily Oil Bulletin
S.K. Saskatchewan
Crescent Point top operator in 2014 on Saskatchewan drilling
Saskatchewan top operators Operator
Tight oil development in Saskatchewan made Crescent Point the top operator in Canada in 2014.
Crescent Point Energy became the top operator in Canada during 2014—up one spot from the prior year—measured by development and exploratory metres drilled. The company finished the year by drilling 1.63 million metres of hole. Canadian Natural Resources moved down one spot from 2013, to second place, ranked by metres rig released. The company drilled 1.45 million metres. Encana ranked third in 2014 (954,057 metres), followed by Husky Energy with 901,017 metres drilled and Cenovus Energy in fifth place (860,384 metres). For 2014, places five through 10 were Progress Energy Canada (755,110 metres), ARC Resources (639,576 metres), ConocoPhillips Canada (621,554 metres), Tourmaline Oil (609,081 metres) and Pe y to E x plor at ion & D e ve lopme nt (511,617 metres).
Development Exploratory
Total
Crescent Point Energy
463
75
Husky Energy
283
44
327
Teine Energy
245
32
277
Northern Blizzard Resources
227
8
235
Raging River Exploration
83
37
220
Canadian Natural Resources
30
6
46
Beaumont Energy
38
39
Whitecap Resources
04
2
06
Penn West Petroleum
0
-
0
Yanchang International (Canada)
8
5
96
538
Legacy Oil + Gas
83
94
NAL Resources
69
0
79
ISH Energy
77
-
77
Rock Energy
58
7
75
Spartan Energy
59
5
64
Based on wells rig released, Canadian Natural was the top operator with 1,184 wells rig released, followed by Husky (668 wells rig released) and Crescent Point (586). The top 10, based on wells rig released, was rounded out by Cenovus (457), Encana (327), Teine Energy (278), ConocoPhillips Canada (251), Devon Canada Corporation (244), Northern Blizzard Resources (225) and Raging River Exploration (222). The top driller of exploratory wells last year was Crescent Point with 77 wells, followed by Husky with 58 and Canadian Natural with 36. Crescent Point also drilled the most metres of exploratory hole with 264,335 me t r e s. R oy a l D utc h She l l r a n ke d second with 160,695 metres of exploratory hole, followed by Tourmaline with 128,100 metres.
Source: Rig Locator
In Alberta, Canadian Natural drilled the most wells last year (998), followed by Cenovus (435), Husky (313), Encana (274) and ConocoPhillips Canada (248). Crescent Poi nt led t he way i n Saskatchewan with 544 wells rig released, while Husky was second at 354 wells. Teine booked 278 rig releases, followed by Northern Blizzard (225) and Raging River (222). In B.C., Progress Energy Canada led operators by drilling 187 wells. Royal Dutch Shell had 61 rig releases, followed by ARC Resources (59), Encana (53) and Tourmaline (46). T h e m o s t a c t i v e c omp a n ie s i n Manitoba included Tundra Oil & Gas Partnership (167 wells rig released), Corex Resources (64), EOG Resources Canada (51), Elcano Exploration (27), and Crescent Point and ARC Resources each with 20 wells rig released. OIL & GAS INQUIRER • MARCH 2015
31
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OIL & GAS INQUIRER • MARCH 2015
33
Feature
T S E E T O W S
P S
s a e ar ty h ivi c i r ct s d y a Bulletin i qu tne houseDaily Oil i L on tone the M arreltleSs from
g
n hi
s u p
D o By th n wi
W
ith oil prices cut in half in the last six months and gas prices stuck under the $3 level, budgets are being cut in all unconventional oil and gas plays across western Canada. But within those plays are sweet spots that remain economic. In the Montney play straddling the Alberta and B.C. border, those sweet spots are in areas with high deliverability of gas and strong flows of condensate and natural gas liquids. Outside of these areas, drillers are cutting back as in the rest of the basin. A recent report by BMO Capital Markets illustrates why activity remains strong in liquids rich areas of the Montney. The BMO
34
MARCH 2015 • OIL & GAS INQUIRER
study found that even with condensate prices of $50/bbl, the best wells in the Montney could deliver internal rates of return from 30 per cent to 100 per cent. Those returns could even get better as service prices fall along with commodity prices, said Wendy Smith Low, managing director of the energy A&D Advisory group at BMO, speaking at a Canadian Society for Unconventional Resources technical luncheon in January. BMO took a close look at the Montney last November before oil and condensate prices tumbled and determined the best Montney areas could all get internal rate of returns (IRRs) of well over 100
Cover Feature
Seven Generations Kakwa Montney well results Number of Wells
Gas (mmcf/d)
Condensate (bbls/d)
Total (boe/d)
Condensate yield (bbls/mmcf)
IP30
34
4.8
853
1,651
178
IP90
25
4.5
699
1,453
155
IP180
18
3.8
505
1,144
133
Source: Seven Generations Energy
Encana Montney play in focus Land (net acres) Avg. working interest
611,000 81%
EUR/well Oil Gas Well inventory Well costs (DCT) Royalty rate
80,0000–1,000,000 9–12 bcfe 3,700 $8–$10 million 11–15%
2015F production Oil/condensate NGLs Natural gas
5,000–5,500 bbls/d 14,000–15,000 bbls/d 580–620 mmcf/d
2015F capital Net
$250–$350 million
Gross
$600–$700 million
2015F wells Net
20–30
Gross
35–45
Supply cost $/mcfe $/boe
$1.30–$2.00 $30–$40
Source: Encana
per cent. The original analysis was based on assumptions of an AECO gas price of $4/GJ and a WTI oil price of US$90/bbl. BMO recently released a new analysis based on a realized condensate price of $50/bbl. Due to its use as diluent for pipelining bitumen, condensate is the most valuable hydrocarbon in western Canada, trading at a slight premium to WTI. The study focused on the unconventional Montney fairway where favourable combinations of condensate yields, deliverability (initial production rates) and capital costs produce the best economics in the fairway. When high-grading the Montney fairway, BMO analysts focused on reservoir thickness, depth
and pressure, and also on where the rock is most brittle—which allows induced fractures to propagate more effectively. “And so we tended to focus on the western side of the fairway as opposed to the more conventional reservoirs which lie to the east. And we’re definitely not talking about the more conventional reservoirs in the Montney,” Smith Low said. She said the other big high-grading criterion was overpressured reservoir. “As we move west in Alberta and British Columbia, we get into deeper reservoirs. And once we’re deeper, we tend to be more overpressured, which increases deliverability and ultimately storage and capture.” These criteria established a study area of 37,000 square kilometres, or about one-third of the fairway, straddling the AlbertaB.C. border. Smith Low said the Montney has been well developed across the fairway over the past 10 years with production approaching four bcf/d, or about 25 per cent of western Canada’s total gas output. For its study, BMO was looking for outliers that are significantly better than the typical northeastern B.C. Montney well. Those less spectacular areas have an initial production rate of about six mmcf/d but less than 20 bbls/mmcf of natural gas liquids. Smith Low said public production data, especially for condensate, is notoriously bad. To find the sweet spots, BMO instead looked at more than 4,000 gas analyses to hone in on the most interesting areas, then augmented that with available productiontest data and/or corporate disclosures. Pouce Coupe was excluded because it’s a hybrid area with a mix of conventional and unconventional reservoirs and tends to be oily. “We really just wanted to just focus in on the true unconventional outliers,” Smith Low said. BMO identified four outlier areas: Karr/Kakwa, Elmworth/ Wapiti, Septimus and Altares.
Karr/Kakwa According to BMO’s research, the type well forecast for the Karr/ Kakwa areas has an initial production rate of 5.4 mmcf/d with a condensate-to-gas ratio of 150 bbls/mmcf. The estimated recovery is about 5.5 bcf per well with a depth of about 3,000 metres. It can be as much as 50 per cent overpressured. “So this really is truly an outlier,” said Smith Low. “I think the closer you get to the normally pressured gradient and the farther east you move, the more likelihood that you get into the oil window. But for the condensate window, there is a very welldefined sweet spot in this area.” Because of the depth, BMO assumed a well cost of $11 million. Using its original price deck of $4 AECO gas and $90 WTI, BMO gave the Karr/Kakwa areas a rate of return of 350 per cent. Assuming a realized condensate price of $50 today, the IRR drops to 66 per cent. “So it’s still very resilient,” Smith Low noted. Given this resiliency, it is no surprise Kakwa-focused Seven Generations Energy is one of the few operators in western Canada that hasn’t cut its budget in 2015. Seven Generations, who went public in 2014, plans on spending $1.6 billion this year. Since the first half of 2014, Seven Generations’ drilling pace has nearly doubled, with 14 drilling rigs working for much of December, compared to an average of seven rigs running in the OIL & GAS INQUIRER • MARCH 2015
35
Cover Feature
Mapping out the Montney IP30 (mmcf/d)
C5+ (bbls/ mmcf)
Septimus
3.9
Kakwa
5.4
Elmworth Altares Sunrise
EUR (bcfe)
% liquids
100
7.1
46
4.7
0.8
150
10.8
54
11
3.3
5.8
75
8.3
40
9.0
2.6
5.4
42
8.0
31
10
2.6
5.9
8
5.0
14
5.9
0.9
Attachie
1.0
100
1.4
46
5.9
0.9
Jedney
3.8
15
2.4
23
5.0
0.8
Nig
4.1
25
4.1
27
5.0
0.8
Blueberry/Inga
3.0
50
3.6
35
5.0
2.2
Play area
Well cost ($millions)
Drill credit ($millions)
Source: BMO Capital Markets
first half of 2014. The company expects to have 15 drilling rigs operating by mid-2015. “Given the high quality of our Kakwa River project, particularly the now well-delineated region that we call the ‘Nest,’ we expect prices sufficient to encourage development,” company chief executive officer Pat Carlson says. “With 15 rigs, we believe that our lowest cost supply, ‘Nest 2,’ has approximately seven years of development inventory.” Seven Generations is at a relatively early stage of development at its Kakwa River project with only about 80 wells drilled while thousands are planned. “We have made considerable progress towards evolving efficient drilling and completion practices, but we think we can do more to improve our capital efficiencies and well productivity,” says company president Marty Proctor. Seven Generations has been testing different well spacing and is currently assuming three layers of wells will be required to optimally exploit the Montney. “The single-layer well spacing that we have tried ranges from 160-metre inter-well spacing, which is equivalent to 10 wells per mile, to 400 metres, which is equivalent to four wells per mile,” Proctor says. “All of these tests were done with 1.5 tonnes of proppant per metre of frac interval. We have also done some testing with larger-sized fracs to determine whether further productivity gains may be achieved with larger frac sizes. At this stage we don’t know whether we will get the best overall total value with a lot of wells with large fracs or less wells with very large fracs.” He says there are other technical choices to be optimized— including frac fluid, frac design, proppant type, proppant concentration, liner design, pad size, well trajectories, a new friction-reducing mechanical device that members of the drilling team designed, improved bit designs, improved drilling mud 36
MARCH 2015 • OIL & GAS INQUIRER
systems (including underbalanced drilling), larger drilling clusters to dilute the costs associated with rig moves, and to minimize the amount of surface land use and more efficient surface equipment. Seven Generations is also taking a non-standard approach to managing the high initial decline rates that characterize unconventional plays. The company deliberately restricts the initial production rates of new wells. This slow-back production method means facilities don’t need to be sized for short-lived peak rates. Also, wells don’t decline as fast, and Seven Generations believes that the production practice improves its liquid recovery rates. Due to this production practice, Seven Generations cautions investors that it isn’t comparable to other producers by peak production rate. Seven Generations says it was braced for low commodity prices. “We entered the business knowing that to compete in an oversupplied environment, we would need to have low supply costs,” Carlson says, but adds: “We did not know that the low price environment was going to come upon us in the autumn of 2014, and we did not know if it would be oil or gas that would be the fi rst oversupply dam to break. We built the company around the notion that we would need to be competitive and fi nanceable in the type of energy price environment that we have recently experienced.”
Elmworth/Wapiti In the Elmworth and Wapiti areas, BMO assumed an initial production rate of about 5.8 mmcf/d and a condensate yield of about 75 bbls/mmcf. Because the reservoir is a bit shallower the well cost is about $9 million. However, the potential for hydrogen sulphide can increase development costs.
Cover Feature
Using last fall’s pricing assumptions, the Elmworth/Wapiti IRR exceeded 220 per cent, dropping to 69 per cent with a realized condensate price of $50/bbl. Apache has 148,000 prospective wells for the Montney at Wapiti. For 2015, the company has earmarked one rig to drill eight horizontal wells in its inventory of 900 horizontal locations for the Montney. Newly appointed president and chief executive officer of Apache, John Christmann, said late last year that the company is in the early stages of testing its Wapiti Montney play, along with the Duvernay play, in western Canada. The company plans on leveraging its knowledge in U.S. shale plays to fine-tune its Montney strategy. “The key here is to take the unconventional U.S. mindset to the supply-chain approach in Canada—how do we take costs down, maximize recovery and minimize cost,” he said. “On the supply chain side, you look at equipment, sand, chemicals and water,” added Navneet Behl, Apache vice-president of operations for unconventional resources. “If you can control and manage these four key strategic elements, then you can develop the play at the rate you want to ramp. It can go from two rigs to 40 rigs if you have everything lined up here. These are your major constraints and your major costs that will change the face of the play.” Apache plans to test the lower Montney this winter, with the belief there could be a potential inventory increase of 50 per cent. The company will test a 1.5-mile lateral here as well, and management foresees potential savings through integrated frac-water recycling and disposal.
The tap will continue to be open on the Montney in 2015, despite low prices. Control of infrastructure will be one of the key factors of success.
Septimus The initial production rate of the Septimus well type is significantly lower at 3.9 mmcf/d in the BMO study. The condensate yield is 100 bbls/mmcf. However, the IRR was 440 per cent at last fall’s pricing assumptions, and still an impressive 95 per cent with $50/bbl condensate. “And that really comes from the fact that the capital to drill, case and complete these wells is significantly less at $4.7 million,” the BMO analyst said, due to the shallow nature of the play. Crew Energy has 487 sections of land in the Septimus/Parkland/ Tower area of the Montney, with 2,850 potential drilling locations. In the first half of 2015, Crew plans to finish construction of its second 60-mmcf/d gas plant at West Septimus, which will double its natural gas and liquids handling capacity in the area. The company will also complete 12 wells that were drilled last year and are to be tied in to the new gas plant in the second half of the year. Completing these wells will allow commissioning of the West Septimus facility early in the third quarter. Also this year, Crew plans to drill eight new pad wells at its liquids rich gas development at Septimus, and drill two new wells and complete four wells at its light oil development at Tower, B.C., which are all expected to come on stream in the second half of 2015. The company will also install the necessary surface equipment and pipeline tie-in for liquids handling at Septimus, which will eliminate the trucking of condensate and enhance the area netback. Altares When BMO did its original study, the Altares area came in with an IRR of 98 per cent—two percentage points below the cut-off for OIL & GAS INQUIRER • MARCH 2015
37
Cover Feature
BMO’s definition of an outlier area. But it was included because a small drop in capital costs could easily move the rate of return above 100 per cent. Assuming a realized condensate price of $50/bbl, the Altares IRR drops to 34 per cent, the lowest of BMO’s four outlier areas. Initial production rates here are about 5.4 mmcf/d, but the condensate yield here is significantly less at 42 bbls/mmcf. “But what you’ll note is that the decline rate is much shallower than what we saw on some of the other outlier areas,” Smith Low said. Because the reservoir is deep, the Altares area well cost is about $10 million. But the area is west of the B.C. government’s drilling credit line, enabling wells in the area to receive a full Tier 2 drill credit. Private producer Canbriam Energy has established a drilling inventory of 700 net locations in the Altares play, with current production of around 10,000 boe/d. In 2014, Canbriam reported plant yields of 40–50 bbls/mmcf of production, broken down into 60 per cent condensate, 20 per cent propane and 20 per cent butane. Since 2008, it has drilled 11 exploration wells and 13 development wells in the Montney. Canbriam plans on operating three of four rigs in 2015, depending on market conditions. Under the four-rig scenario, it expects to exit the year at 40,000 boe/d.
Pushing ahead While it will be harder to de-risk emerging Montney areas and move them into development at current prices, Smith Low said the “true outlier areas…will be a focus of development in the next year because they will provide some of the best rates of return across the basin.” She said a key element is control over infrastructure. “I can’t emphasize that enough. When we’re producing this amount of liquids on a daily basis out of these wells, we don’t want to be trucking that long term. Those trucks on the roads are not safe for our workers out in the field; they’re not safe for the residents in the areas that live there. We really want long-term take away solutions for stabilized C5+. And so that includes, for the most part, pipelining. So those that can come up with an infrastructure development plan—one that sees development for this year, next year and five years out and accommodates that—will be the winners.” With plummeting oil prices, BMO is hoping for continued improvement in capital efficiencies. “If there’s one bright light to what we’ve gone through in the last eight weeks in terms of declining commodity prices, it’s that perhaps we’ll see a bit of a reset in capex and costs overall,” said Smith Low. “I think that will be advantageous and encourage future development.... If we can alter our capex by 25 per cent, that goes straight to the bottom line. “There is very little in the Western Canada Sedimentary Basin, on single-well economics, that can beat these best Montney areas.”
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Back to the future
Feature
Low prices generate growing interest in recompleting older unconventional wells By Darrell Stonehouse with notes from the Daily Oil Bulletin
W
ith over 1,100 service rigs active in Canada, along with 326 coiled tubing spreads, the well completion and intervention sector is well supplied. Precision Drilling, Canada’s largest service rig provider, reported utilization hovered around 33 per cent in the first nine months of 2014 as too many rigs competed for too little business. Hourly rates grew from $844 in 2013 to $922 in 2014, a 9.2 per cent increase. The well servicing marketplace, however, could go under a resurgence in 2015 as low oil and gas prices drive operators to look for cost-efficient means to maintain and increase production. Driving this resurgence could be a rush of recompletions of unconventional wells drilled early in the horizontal drilling and multistage fracturing revolution. By going back into these earlier wells and refracking, operators are hoping to add profitable production to weather the commodity price storm. The recompletion wave has already started in U.S. shale plays, according to industry analysts Wood Mackenzie. “Over the past year, lower U.S. natural gas prices drove Marcellus operators to shift attention to horizontal refracs in order to increase recovery rates at reduced costs [approximately 25 per cent lower expenses for a standard well],” the analysts reported in early January. “Successful refrac testing also took hold in gas-rich plays like the Haynesville and Barnett, where some operators were able to re-set production rates to early-life profi les and, in some cases, increase performance.” Encana has targeted the Hayneville shale play with great success, Executive vice-president and chief operating officer Mike McAllister reported in August. “In the Haynesville, we have implemented a refrac program with excellent results on the first two wells,” he said. “Inititial production rates are 100 per cent higher than expected.” McAllister said production from the wells came in at four mmcf/d, up from around one to two mmcf/d before the treatment. “The cost of a refrac is running at around $1 million, where drilling a new well in the Haynesville is running at
about $12 million, so you got a significant reduction in that,” he said. “It’s a little early to call in terms of the expected ultimate recovery coming out of these refracs in terms of how they decline. But the initial results are very encouraging with tremendous payouts and return on investment.” Encana recompleted five more wells in the Haynesville in the third quarter. And was again pleased with the results. But McAllister said more work needed to be done. “We’re doing microseismic on the wells and running tracers and we’ve been able to determine we’re only getting the first 25 per cent of the wellbore stimulated from the heel of the well,” he explained. Encana is now in the process of expanding its refrac program, including looking for refrac candidates in the Montney play straddling the Alberta and B.C. border. “We’re now moving that technology to other parts of our portfolio,” said Encana president and chief executive officer Doug Suttles. “We’re testing it in other places. There’s still some technology development though that needs to happen. I think our assessment shows that we’re only refracking a portion of the well. And so one of the things we’re debating is about how fast to go and let the technology evolve. So go at a more moderate pace as we see that and also test it in new places.” Foothills gas producer Ikkuma Resources has plans to spend the majority of its $23-million budget this year on recompletion and optimization projects after finding success going back into wells in 2014. The company’s recompletion program has to date tested 1,667 boe/d net (100 per cent natural gas). Tie-in of these volumes is not anticipated until late in the third quarter of 2015 due to regulatory delays related to caribou habitat protection. The company plans on spending $11 million on the program in 2015 in an effort maintain production through the downturn. Hawk Exploration is also focused on recompletions in 2015, says Steve Fitzmaurice, Hawk president and chief executive officer. “The capital outlay for recompletions is one-fifth of a new well,” Fitzmaurice tells the Daily Oil Bulletin. “If you OIL & GAS INQUIRER • MARCH 2015
39
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can get a similar net production out of the well, then it is much more capital efficient.” According to his company’s operational and 2015 budget update, released in December, Hawk identified several well recompletion candidates at Forest Bank, Sask., where the company anticipates it can add production with low capital costs and planned one (0.65 net) recompletion in the first half of the year. “At the time we wrote that, the recompletions plan was not in light of lower oil prices—it was just the opportunities in front of us,” Fitzmaurice says. “However, given where the price of oil has moved, this will take up a larger chunk of our 2015 budget, just because it is more capital efficient.” Wood Mackenzie says that refracs start to look better than new fracs as the drop in oil prices leads to what it considers an unprecedented level of uncertainty in 2015, especially for the prospects of the North American upstream oil and gas sector. “I would say this year, more than in any of the last five, recompletions will share a lot of the limelight and a lot of the attention—it is more of a capital-efficiency thing,” Jonathan Garrett, principal analyst at Wood Mackenzie, says. “If you’re working with a budget that has been cut, then what is the biggest bang for your buck. If you have wells on your acreage that have been drilled or completed in 2009 and your budget has just been cut by 40 per cent, then one thing you can do is pop the wellhead off, hit it with a lot more horsepower, get the production profile to look similar—or even better, sometimes—to when you originally fractured it,” he explained. “Instead of spending $8 million on a new well, you spend $1 million.” Even during periods of $100/bbl oil, such as most of last year, there has been quite a bit of time and money spent on recompletions, Garrett says. However, at $100/bbl oil prices, what often makes more sense for companies is to drill the biggest, best wells with the highest initial production rates and highest estimated ultimate recoveries. For an operator with “prime, Tier-1, A-plus acreage,” Garrett says, the focus would be to exploit that acreage and drill the best wells, even at current prices, which makes sense given the fact that service costs are going to come down. “However, in the event that you are an operator who built your company around Tier-2 or Tier-3, or speculative,
marginal acreage at today’s prices, then it is probably more efficient for your capital to locate a well you’ve drilled in the past, and apply some of these new completions techniques to the well.” During the current period of low commodity prices, recompletions will fi rst focus on wells drilled several years ago before the big step-change in technology, he adds, which is why in the U.S. he has noticed recent refracturing primarily in gas plays such as the Fayetteville and Haynesville, rather than areas such as the Bakken and Eagle Ford. “This is not a function of [Fayetteville and Haynesville] being gas plays. It is just that the technology for the unconventional business in 2008 relative to even 2010 is a nightand-day difference. It has to do with the volume of fluid being pumped, it has to do with how quickly that fluid is being pumped and it has to do with how much sand is being pumped with it. “Also, if you look at things such as stage count, these were very, very early-on unconventional wells, and in terms of upside you get a lot on a recompletion of one of those types of wells. If you were to recomplete a well drilled in the Bakken in early 2014, it would not make sense because the technology between early 2014 and now is not going to be enough to justify revisiting that well.” For producers trying to hold onto a particular acreage, notes Garrett, refracs are not favourable. “You will still have to drill one-off wells here and there to get that acreage held. Otherwise, you will relinquish that acreage to someone else.” He adds, “If I were to give two factors that are probably most important for identifying the well to refrac, it would be the age, as well as the distance between that particular well and other wells in the area. One thing you do not want to do is refrac a well that is within close proximity to a lot of other wells, because you’re changing the structure of that formation during that refracturing process, in which case you might accelerate decline of a nearby well. “There are things you could do to mess up wells in the neighbourhood. So you look for older wells with regards to their technology, and then you look for wells with quite a distance away from those nearby.”
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Feature
Price and activity forecasts paint picture of a tough year ahead In late January, western Canada’s oil and gas industry began to weigh the carnage caused by the collapse of oil prices and an equally troubling decline in gas prices. The news is not good. FirstEnergy Capital is forecasting WTI oil prices to average US$54.50 for 2015 while Brent is expected to average $59, but a price recovery is expected to be “lower and slower” than in previous cycles. Martin King, vice-president of institutional research, noted in mid-January the market has experienced a price collapse on par with that of the 2008-09 fi nancial collapse. The current oversupply in the global market is estimated at 1.5 to two million bbls/d. Onshore and off shore storage capacity is starting to fill rapidly, driven by the price contango. Furthermore, global demand growth is subdued: Asia and China remain concerns, Europe is a “basket case” and the U.S. is the only market seeing strong demand growth. Synthetic light crude is expected to average C$62.99 for the year, Western Canadian Select (WCS) is forecast to average $42.22, while Edmonton Light is forecast to average $56.20 for 2015.
Hunkering Down By Darrell Stonehouse
with notes from the Daily Oil Bulletin OIL & GAS INQUIRER • MARCH 2015
41
Feature 5.0
FirstEnergy natural gas price outlook ($/mmBtu)
4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0
NYMEX (US$)
AECO (C$)
US$-C$ exchange
Q1
Q2
Q3
Q4
Average
2015
Average
2016
Average
2017
Source: FirstEnergy Capital
FirstEnergy Canadian crude oil outlook (C$/bbl)
100 90 80 70 60 50 40 30 20 10 0
Synthetic Light
WCS
Edmonton Light
Q1
Q2
Q3
2015
Q4
Average
Average
2016
Average
2017
Source: FirstEnergy Capital
TD Economics is even more pessimistic. It reported in late January it expects WTI oil prices to average around $41 per barrel in the first half of 2015, and just $53 per barrel in the second half of the year. While oil prices have taken a beating, the natural gas price picture isn’t much better, with AECO expected to average C$2.28/mmBtu for 2015, a drop from the 2014 average of $4.52, according to the latest outlook from FirstEnergy Capital. NYMEX is also expected to experience a sharp drop to average US$2.63/mmBtu for the year compared to $4.27 for 2014. “December 2014 was pretty much a bust in terms of heating degree days— the third warmest in 30 years,” King said. “We’ve lost a lot of consumption out of there in that month.” U.S. domest ic supply e x pa n sion remains very robust, with solid supply growth happening in Canada as well. “We lowered our forecast again for natural gas to reflect, basically, this increasing gas storage situation,” King said. “December kind of just threw us offside; January has been pretty good so far. “The idea that we’re driving towards here with the natural gas story is to say 42
MARCH 2015 • OIL & GAS INQUIRER
that prices in a sense have to be similar to what they were in 2012. Prices have to go low enough to incentivize demand from the power generation sector to clean up this storage oversupply, to clean up the growth that’s happening in supply and prevent a storage blowout by the end of October.”
Low prices drive capital expenditures downward Low oil and gas prices will have a major impact on capital spending, according to the Canadian Association of Petroleum Producers (CAPP). On January 21, CAPP released a shortterm review of its 2015 forecast, predicting a 33 per cent decline in short-term capital spending in 2015 and a projected slowdown in growth of oil production from its prior forecast by about 65,000 bbls/d in 2015 and 120,000 bbls/d in 2016. “No quest ion, t he ef fec ts on t he industry are sharp,” says CAPP president Tim McMillan. Accordi ng to t he rev iew, capita l investment in western Canada, including the oilsands, will total $46 billion in 2015, down 33 per cent from $69 billion
invested in 2014. In the oilsands, 2015 capital investment is forecast at $25 billion compared to $33 billion last year. Capital spending in the conventional oil and gas portion of the Western Canadian Sedimentary Basin is forecast to decrease to $21 billion this year from the $36 billion invested in 2014. The total number of wells to be drilled in western Canada this year is forecast to decline by 30 per cent to 7,350 wells. “These are challenging times, and Canadians across the country will see or feel the impacts,” McMillan says. “Purchases will be down, including purchases from the more than 2,300 businesses from coast to coast, excluding Alberta, that sell goods and services directly to the oilsands. Investors have seen their portfolios shrink. And governments will see reduced revenues from the industry’s royalty and tax payments. We all will feel the effects.” Industry capital expenditures are a moving target, according to TD Securities. In early December, TD analysts studied the spending plans of 50 domestic producers it covered and predicted capital expenditures of $53.4 billion.
Feature
“Fast forward two months and almost all companies have provided guidance, and the total spending is now 21 per cent lower, at $42.2 billion,” TD says. And it could get worse. “We could see companies move closer to cash flow neutral budgets in 2015,” TD writes. “If all the companies under coverage reduce spending to this level, the total capex spending number could go as low as $21 billion, assuming that the $10 billion in dividend payments remain unchanged for the year.”
Lower capex means huge cut in field activity As a result of the capital expenditure cuts, the Canadian Association of Oilwell Drilling Contractors (CAODC) expects 6,612 wells will be completed in 2015, off from a total of 11,534 wells completed last year. CAODC issued its original 2015 drilling activity forecast on Nov. 20, 2014, with an assumption of oil (WTI) at US$85/bbl. The updated forecast uses an assumption of WTI at US$55/bbl. The number of active drilling rigs in service is expected to decline from an average of 370 per day in 2014 to 203 in 2015 (minus 41 per cent). Fleet utilization is also expected to drop from 46 per cent in 2014 to 26 per cent in 2015. “The new reality of $55 oil means that the entire industry will hurt for a period, and drillers and service rig contractors are not immune to that,” says CAODC president Mark Scholz. “We have been through rough patches before and come out strong on the other end, and I’m confident that we will do that again, but right now, that’s going to involve buckling in.” CAODC also projects that decreased drilling activity will hurt employment in the oilpatch, resulting in the potential loss of approximately 3,400 direct jobs and up to 19,500 indirect jobs relative to 2014. Total net job losses (direct and indirect) could reach as high as 23,000 compared to last year. “Times like this are tough not just on contractors, but on their employees as well. If there are not as many drilling rigs working, there will not be as many rig workers on the job. This will have significant adverse effects on indirect employment throughout the economy, well beyond just rig workers,” said Scholz. The Petroleum Services Association of Canada (PSAC) is a little more optimistic than CAODC, but only a little.
PSAC updated 2015 forecast by province
8,000
7,650 404 77
7,000
6,000
5,000
4,187 5,899
4,000
3,000
2,679
2,000
1,000
Service
0 Dry
364
415
Total
Oil
Gas
(4)
B.C.
Alberta
Saskatchewan
Manitoba
1,270
Total
Source: PSAC
CAODC revised forecast overview 2015 total wells (western Canada): 6,612 Active rigs
Fleet
Utilization
Operating days*
Q1
Quarter
%
,
Q2
%
,
Q3
%
,
Q4
%
,
203
795
26%
76, 696 (total)
AVERAGE 2015
Assumptions: WTI: US$55/bbl; AECO: C$3/mcf; 11.6 days/well *Calculation based on spud-to-rig-release data
PSAC has revised its forecast number of wells drilled (rig released) across Canada for 2015 to 7,650 wells. This is a decrease of 2,450 wells from PSAC’s original 2015 drilling forecast released in late October 2014, representing a 24 per cent decline. PSAC is basing its updated 2015 forecast on average natural gas prices of C$2.50/mcf (AECO), crude oil prices of US$57/bbl (WTI) and the Canada-U.S. exchange rate averaging 84 cents. On a provincial basis for 2015, PSAC now estimates 4,187 wells to be drilled in Alberta, down from 5,740 wells in the original forecast. Approximately 25 per cent
Source: CAODC
fewer wells are also expected to be drilled in B.C., with PSAC’s revised forecast now at 415 wells for the province down from 555 in the original forecast. The revised forecast for Saskatchewan now sits at 2,679 wells compared to 3,365 wells in the original forecast, and Manitoba is forecast to see 364 wells or a decline of 66 in well count for 2015. “The rapid decline of oil prices over recent weeks is taking hold,” says Mark Salkeld, president and chief executive officer of PSAC. “There is enormous pressure on services companies to cut costs even in the face of slim margins. They are OIL & GAS INQUIRER • MARCH 2015
43
Feature
responding, and some difficult times may lie ahead in the immediate term, but companies are focusing on what can be done now to keep key personnel, enhance efficiencies and optimize operations.”
Demand for service price cuts will get worse Service companies are already feeling cost pressures from operators, and they are going to get worse without a major upswing in commodity prices. The current cost structure is outdated given the crash in oil prices, Neil Smith, chief operating officer of Crescent Point Energy, told the CIBC 18th Annual Whistler Institutional Investor Conference in January. It worked when oil was fetching around $100/bbl, but “cannot exist” when oil is trading below $50/bbl.
“The guys that don’t cut, we’re not going to use.” — Neil Smith, chief operating officer, Crescent Point Energy
“The cost structure has accelerated to $100 oil and this is going to have to change,” he said. “We appreciate our partnerships with a lot of our suppliers and we need them healthy for when things get busy again, but in the near term they have to cut. The guys that don’t cut, we’re not going to use.” Crescent Point started talking to vend ors last November, and the first decreases bandied about were in the 10 per cent range, Smith said. “Well, that’s a good start, and I appreciate that, but first of all, when you are at
100 bucks the margins are pretty wide, so that’s cutting out of a pretty large margin,” he said. “The other thing is their fuel costs have come down. Fuel for most industries is a big driver in their cost structure, so 10 per cent is really not that much of a saving,” he told the conference. In the last downturn, Crescent Point says it saw a 30 per cent reduction in service costs. Tom Buchanan, president and chief executive officer of Athabasca Oil, expects service sector price decreases in the 10–20 per cent range. “We think we can achieve within those numbers and maybe at the higher end of that range. I think those types of cost savings are there for us coming into the second half of the year,” he says. Buchanan says that before Christmas, the company was contacting service providers seeking pricing relief, but the tables have now turned. “I’d say now it’s the other way around. I think there’s going to be some more competition for costs there that’s going to be healthy coming out of the first quarter this year, particularly on rigs and for frac services,” he says. Steve Haysom, a senior vice-president with Seven Generations Energy, says the company is working with “every single one” of its suppliers and contractors in an effort to reduce costs. “When things are booming, you’re talking $18,000, $20,000, $22,000 per day per rig. You could see those costs coming down significantly,” he says. “We don’t know what they’re going to look like, but we do know and we do expect there to be some savings from that perspective.”
Due to the cuts, industry analysts agree some producers are “putting the screws” to service companies. According to Michael Mazar, oilfield services analyst with BMO Nesbitt Burns, producers are applying the pressure “across the whole spectrum of the different service lines.” “It’s happening already,” he says. “In Canada, it gets masked a bit by the winter drilling season. It doesn’t happen as quickly on the pricing side. But if you look to the U.S., it’s a better indicator of where Canadian pricing will go once breakup is over.” Since December 2014, day rates for drilling contractors in the U.S. are down 10 to 15 per cent, he said. Among industry analysts, there’s a sense that some service contractors will be harder-hit by the downturn than others. For Scott Treadwell, director of equity research for TD Securities, pressure pumping companies in particular will face stronger headwinds than other contractors, due to two factors. The first is the matter of contracted capacity. “There is really no such thing,” says Treadwell. “The market is much more spot-oriented.... Contracted volumes are less, and because well profiles have gotten bigger…it’s easier for producers to meet any older, contracted volumes they have.” The second factor is fixed costs. While well servicing contractors, for example, do not pay field employees who are not working, most pressure pumpers have field staff on salary. “Pressure pumpers are going to have some issues with fixed costs, and I would expect to see salary rollbacks as the first step,” he says. Near term, he expects few pressure pumpers to layoff staff in the first quarter,
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Feature
Drilling companies are already taking a big hit, with Precision Drilling reporting 1,000 workers are now sidelined.
since most will be busy. Indeed, he expects Canadian pressure pumping contractors will not likely see much opportunity to pare fixed costs—including payroll— until April or May. Much of the downturn’s impact is expected to depend on geography, and Treadwell expects small to mid-size service contractors in places like Saskatchewan will feel the pinch, largely because such markets are heavily serviced. “You’ve got a lot of service providers, but very few producers. There might be half a dozen senior producers working in
Saskatchewan and 50 service companies trying to work for them,” he says. “That’s going to turn into a knife fight.” The outlook is brighter in places like Alberta’s Deep Basin, where some 20–30 producers are working a landscape with fewer ser vice contractors competing against one another, making for a more balanced market overall. “That’s not to say Deep Basin producers won’t be chasing lower pricing. They will, but it’s not like you’ve got 10 other service contractors waiting for that job. You might have two, three or four waiting.”
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Backed by industry-leading warranties, NOSHOK’s broad offering of pressure, level, temperature and force measurement instrumentation, along with needle & manifold valves address applications including: Upstream
Midstream
Downstream
Well Servicing
Offshore
NOSHOK Corporate Headquarters I 1010 West Bagley Road I Berea, Ohio 44017 I P: 440.243.0888 I F: 440.243.3472 I www.noshok.com
OIL & GAS INQUIRER • MARCH 2015
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advertisers' index Annugas Compression Consulting Ltd . . . . . . . . 20
Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . . 4
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22
Ar-Tech Coating Ltd . . . . . . . . . . . . . . . . . . . . . . . 40
Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Polaris Industries . . . . . . . . . . . . inside back cover
Baker Hughes Canada Company . . . . . . . . . . . . . . . . . . outside back cover
Hotsy Water Blast Manufacturing LP . . . . . . . . . . 15
Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . . 11
Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . . 19 BC Research . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Jim Pattison Lease . . . . . . . . . . . . . . . . . . . . . . . . 26 Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 23 Mainland Machinery Ltd . . . . . . . . . . . . . . . . . . . 27 CanOils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 27 Chase Operator Training . . . . . . . . . . . . . . . . . . . 23 Noshok . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 dmg events . . . . . . . . . . . . . . . . . . . . . . . . . 24 & 28
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MARCH 2015 • OIL & GAS INQUIRER
NOV Completion & Production Solutions . . . . . . . . . . . . . . . . . . . inside front cover
RedGuard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Saskatchewan Oil & Gas Show . . . . . . . . . . . . . . 30 Scott Builders Inc . . . . . . . . . . . . . . . . . . . . . . . . . 38 STEP Energy Services . . . . . . . . . . . . . . . . . . . . . 32 V J Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . . 6 Wise Intervention Services Inc . . . . . . . . . . . . . . .16
NEW! 75 HP PROSTAR ® EFI ENGINE | 60" TRAIL CAPABLE WIDTH | 13.2" REAR SUSPENSION TRAVEL | THE FASTEST ACCELERATING 60" RZR EVER
INTRODUCING THE ALL-NEW 2015 POLARIS® RZR® S 900 FROM THE #1 BRAND IN OFF-ROAD COMES THE MOST TRAIL-CAPABLE POLARIS RZR EVER DEVELOPED The all-new 2015 Polaris RZR S 900 delivers the ultimate combination of industry-leading power, suspension and agility. Own the trail with 40% more power, 13.2" of rear travel and FOX 2.0 Podium X suspension, industry-leading acceleration, a narrow turning radius and high-performance true on-demand all-wheel drive. Inspired by you, the next generation of razor sharp trail performance has arrived. ®
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CHECK OUT GREAT DEALS » SEE YOUR LOCAL POLARIS DEALER FOR DETAILS
WARNING: The Polaris RZR ® can be hazardous to operate and is not intended for on-road use. Driver must be at least 16 years old with a valid driver’s license to operate. Passengers must be at least 12 years old. Drivers and passengers should always wear helmets, eye protection, and seat belts. Always use cab nets or doors (as equipped). Never engage in stunt driving, and avoid excessive speeds and sharp turns. Riding and alcohol/ drugs don’t mix. All drivers should take a safety training course. Call 800-342-3764 for additional information. Check local laws before riding on trails. FOX® is a Registered Trademark of FOX Factory, Inc. All rights reserved. ©2015 Polaris Industries Inc.
2015 RZR® S 900 EPS WHITE LIGHTNING
2015 RZR® S 900 EPS TITANIUM MATTE METALLIC
BUILD YOUR ULTIMATE RZR® AT POLARISRZR.COM
“Anyone who wants to dig a well without a Hughes bit can always use a pick and shovel.” – Howard Hughes Sr. (1869-1924)
Significantly reduce your drilling time in the Montney and Duvernay. R.C. Baker received a patent in 1907 on a casing shoe that advanced well cementing. Howard Hughes Sr. invented the first roller cone drill bit the following year. Since then, thousands more inventions have come from ideas by Baker Hughes employees. For example, our innovative Kymera™ drill bit technology combines the cutting superiority of PDC fixed cutters and the rock-crushing strength of roller cones into a single, patented design to reduce drilling time in the most complex applications. From drilling and evaluation to completion and production services, call us or visit BakerHughes.com/Canadian-Unconventional and let us help you build a better well. +1-877-285-9910
© 2015 Baker Hughes Incorporated. All Rights Reserved. 42623 01/2015