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CONTENTS
FEBRUARY.
in the news
Midstreamers adding fractionation capacity
regional news
British Columbia
Northeastern Alberta
Southern Alberta
Painted Pony to spend $295 million in 2015
Cenovus slows development
Is southern Alberta the next big
Northwestern Alberta
thing, asks the Geological Survey
Central Alberta
of Canada
Bonavista lowers spending plans
Saskatchewan
Delphi hacks back budget
Crescent Point cuts budget by 28 per cent
features Cover Feature
Fast forward Despite low prices, Duvernay drilling expected to remain steady
every issue
Stats at a Glance
Political Cartoon
Grinding it out Heavy oil producers look to tough out price collapse
Cover design: Peter Markiw
OIL & GAS INQUIRER • FEBRUARY 2015
3
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Editor’s Note Vol. 27 No. 2 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles com CONTRIBUTING WRITERS
Lynda Harrison, Richard Macedo, Pat Roche, Elsie Ross
Pushing the
EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles com
reset button
EDITORIAL ASSISTANCE
Laura Blackwood, Sarah Maludzinski, Jordhana Rempel CREATIVE CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles com CREATIVE LEAD
Cathlene Ozubko | cozubko@junewarren-nickles com PRODUCTION COORDINATOR
Janelle Johnson | jjohnson@junewarren-nickles com GRAPHIC DESIGNER
Peter Markiw
CREATIVE SERVICES
Western Canada’s oil and gas industry has
So far, most operators are avoiding major
moved from cautious optimism to survival mode
layoffs, with the only significant announced cut-
early in 2015.
back coming from Shell Canada, which affects
As oil and gas prices continue cratering, capital budgets are being slashed across the
300 of its workers, and Suncor, which laid off 1,000 workers in mid-January.
Paige Pennifold
board, including some very large retreats by the
SALES
industry’s most active drillers. Canadian Natural
pany workers could fi nd themselves in trouble,
Nick Drinkwater, Diana Signorile
Resources cut $2.4 billion from its budget in mid-
according to Claudine Vidallo, Petroleum
SALES
January, a 28 per cent drop from its November
Human Resources Council of Canada, project
guidance. Crescent Point Energy cut its budget
manager of labour market information.
SENIOR ACCOUNT EXECUTIVES
Rhonda Helmeczi, Mike Ivanik, Nicole Kiefuik, James Pearce, Blair Van Camp
But if the carnage continues, service com-
by 28 per cent as well, with plans to spend $1.45
Vidallo says maintaining an experienced
billion this year. Oilsands giant Cenovus is cut-
workforce through industry downturn is the big-
Lorraine Ostapovich | atc@junewarren-nickles com
ting back 15 per cent to between $2.5 billion and
gest challenge facing companies grappling with
DIRECTORS
$2.7 billion, while competitor MEG Energy is
the impact of lower commodity prices.
PRESIDENT & CEO
cutting its budget from $1.2 billion announced in
For advertising inquiries please contact adrequests@junewarren-nickles com AD TRAFFIC COORDINATOR—MAGAZINES
Bill Whitelaw | bwhitelaw@junewarren-nickles com SENIOR VICE-PRESIDENT, ENERGY INTELLIGENCE
Bemal Mehta | bmehta@junewarren-nickles com VICE-PRESIDENT, SALES OPERATIONS
December to only $305 million. A survey of 110 Canadian oil companies
Donovan Volk | dvolk@junewarren-nickles com
completed by Cowen and Company in mid-
VICE-PRESIDENT, GLACIER BUSINESS DEVELOPMENT & EVENTS
January predicts capital expenditures will
Ian MacGillivray | imacgillivray@junewarren-nickles com DIRECTOR OF SALES & MARKETING
Maurya Sokolon | msokolon@junewarren-nickles com DIRECTOR OF THE DAILY OIL BULLETIN
Stephen Marsters | smarsters@junewarren-nickles com DIRECTOR OF DIGITAL STRATEGIES
Gord Lindenberg | glindenberg@junewarren-nickles com DIRECTOR OF CONTENT
Chaz Osburn | cosburn@junewarren-nickles com DIRECTOR OF PRODUCTION
“It is pretty devastating to service companies whenever the economy goes this way, and it is harder for them to look at the longer-term picture because they are operating on contracts,” says Vidallo. “We are hearing that service companies
decline by around 24 per cent from $44.6 billion
are seeing some activity reduction, but there
to $34 billion in 2015.
are still activities proceeding and not stopping.
The capital expenditure bloodletting is
They are optimistic about that,” she says, adding
already being felt by the service industry, and
that drillers especially experience impacts from
there’s more pain to come.
project delays, and they are not necessarily
Crescent Point president and chief executive officer Scott Saxberg says his company’s 2015
hiring back typical workforce numbers. The rate of hire-backs post-breakup 2015
Audrey Sprinkle | asprinkle@junewarren-nickles com
budget assumes an initial 10 per cent reduction
depends on oil prices later this year, Vidallo
OFFICES Calgary
to service costs. Based on conversations to date
notes, but from what her group has heard from
with its service providers, the company antici-
employers, after spring breakup, many service
pates that even greater cost reductions are very
companies will likely not recall the same number
likely if a low oil price environment persists.
of workers as perhaps they would normally.
nd Flr- Avenue N E | Calgary, Alberta TE Y Tel: | Fax: Toll-Free:
Edmonton
220-9303 34 Avenue N W | Edmonton, Alberta T6E 5W8 Tel: | Fax: Toll-Free:
MEMBERSHIPS Membership Rate In Canada, year $ plus GST, years $ plus GST Outside Canada, year $
Membership Inquiries Telephone: Email: circulation@junewarren-nickles com Online: junewarren–nickles com GST Registration Number RT Printed in Canada by PrintWest ISSN - | © JuneWarren-Nickle's Energy Group All rights reserved Reproduction in whole or in part is strictly prohibited Publications Mail Agreement Number Postage Paid in Edmonton, Alberta, Canada If undeliverable, return to: Circulation Department, nd Flr- Avenue N E , Calgary,
Alberta TE Y Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
“When prices fell dramatically in 2008-09,
A major reset is under way in western
we were able to realize a 30 per cent reduction
Canada’s industry to bring costs in line with prices.
in our Bakken drilling and completions costs,”
Expect a leaner, meaner industry to come out on
says Saxberg. “We’ll be working hard with our
the other side.
service providers and fully expect to see rates come down even more than they already have.”
Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
N EXT I S S U E March 2015 Activity in the Montney in anticipation of LNG exports, plus a review of the workover business in tight oil plays
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 • FEBRUARY 2015
5
FAST NUMBERS
%
Expected decline in Canadian capital spending due to low oil prices, says Cowen & Company survey.
$. billion Expected decline in capital spending in Canadian dollars, says Cowen & Company survey.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
OTHER
T O TA L
MONTH
OIL
GAS
D RY
SERVICE
T O TA L
Jan
Jan
Feb
Feb
,
Mar
Mar
,
Apr
Apr
May
May
Jun
Jun
Jul
Jul
Aug
Aug
Sep
Sep
,
Oct
Oct
,
Nov
Nov
,
Dec
Dec
,
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
Jan
Feb
Mar
Apr
Jun
May
Jul
Jun
Aug
Jul
Sep
Aug
Oct
Sep
Nov
Oct
Dec
Nov
Dec
Jan
Feb
Mar
Apr
May
*Year-to-date
*
MONTH
Need warehousing space immediately? Most sizes available 2 to 3 weeks from order.
OTHER
TOTAL
Sprung Structures Lease or purchase
Calgary | Alberta
1.403.601.2292
Toll Free: 1.800.528.9899 www.sprung.com/oilgas
6
FEBRUARY 2015 • OIL & GAS INQUIRER
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, December 2014 Source: Rig Locator
Alberta, December 2014 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
OIL WELLS
Alberta
GAS WELLS
Nov
Nov
Nov
Nov
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
%
Southern Alberta
%
TOTAL
WC TOTAL
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, December 2014 Source: Rig Locator
Alberta, December 2014 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
Canadian Natural Resources Limited
ConocoPhillips Canada Limited
Seven Generations Energy
Cenovus Energy
Encana Corporation
Husky Energy
Penn West Petroleum
Alberta
BITUMEN WELLS
Nov
Nov
Nov
Nov
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
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IN THE
NEWS Issues affecting Canada’s E&P industry
Midstreamers adding fractionation capacity By Elsie Ross
As natural gas liquids (NGLs) production in western Canada continues to rise, a growing number of producers are prepared to enter into long-term contracts for fractionation, spurring expansion and debottlenecking projects, both in Alberta and in the Chicago, Ill., area. Although forecast NGL production of 675,000 bbls/d will outpace fractionation capacity in 2015, capacity is expected to catch up with forecast supply of about 750,000 bbls/d by the end of 2017 as new projects come on stream, Michelle Podavin, director of NGL supply for Plains Midstream Canada (PMC), told a recent conference on NGL markets and infrastructure. An additional 177,000 bbls/d of fractionation capacity is currently in the planning or construction stages, increasing total available capacity for western Canadian producers to about 740,000 bbls/d from approximately 563,000 bbls/d, speakers told the Canadian Business Conferences event. The figure excludes about 230,000 bbls/d of fractionation capacity at the Cochrane and Empress straddle plants. Traditionally, NGLs had stable volumes and locations, and there was no need for multi-year arrangements because there was excess fractionation and pipeline capacity, said Podavin. However, today that has changed with the growth in NGLs that has resulted in the full utilization of fractionation and pipeline capacity, she said. “With all these increases, we need to determine how to balance the risks and costs of these large industry investments between producers and midstream companies,” said Podavin. “If midstream companies are able to manage contracting volume ramps as well as provide flexibility, it will benefit producers in transitioning
their short-term pro- Alberta Propane Supply and Demand duction into longSupply Alberta Demand Supply Alberta Demand term growth. In the ( bbls/d) Year ( m/d) long term, to right . . . . size expansions and . . . . . . . . e n s u r e deb ot t le . . . . necks and expan . . . . sions are ready and . . . . built on time, mid . . . . . . . . stream companies . . . . need to collaborate . . . . with producers to . . . . forecast the size and timing requirements Alberta Butane Supply and Demand Alberta Total Total for these new asset Other Supply Demand for Alberta Supply Alberta investments.” Demand Blending Demand Demand B e yond 2 02 0, ( bbls/d) Year (103 m3/d) the estimated flow . . . . . . of NGL m i xes to . . . . 76.8 47.7 Fort Saskatchewan, . . . . 75.6 47.9 . . . . 74.3 47.9 Alta., is expected to . . . . . . exceed fractionation . . . . . . c a p a c i t y, C a r l o s . . . . . . . . . . . . Murillo, economic . . . . . . researcher for the . . . . . . Ca nadia n E nerg y . . . . . . Research Institute Source: Alberta Energy t old t h e c on f e rence. Debottlenecking or construction of (C2+ mix), creating specification ethane new fractionators and, possibly, expanfor delivery to petrochemical producers sion of de-ethanization capacity would be in Alberta and a propane-rich stream of required, he suggested. NGLs for delivery into Keyera’s fractionThe Fort Saskatchewan/Redwater area ation facilities. just north of Edmonton, which currently The gross cost of about $200 million has approximately 230,000 bbls/d of fracincludes pipeline connections and the contionation capacity, is the focus of much of version of a cavern to C 2+ (ethane plus) the activity as it is near the Dow Chemical raw feed storage. site and has good access to rail, truck and The company also is proceeding with a pipeline transport. 35,000-bbl/d C3+ (propane plus) fractionKeyera is currently adding a 30,000ator expansion at an estimated cost of bbl/d de-ethanizer at Fort Saskatchewan, $225 million with an anticipated onwhich is expected to be on stream by the stream date in the fi rst quarter of 2016, end of this year. It will enable the company i n c r e a s i n g t h e s it e t ot a l at For t to process an ethane-rich stream of NGLs Saskatchewan to 65,000 bbls/d, Matt OIL & GAS INQUIRER • FEBRUARY 2015
9
In The News
Miceli, director of Keyera’s NGL business development, told the conference. In Channahon, Ill., Aux Sable is expanding its existing C 2+ fractionation by 24,500 bbls/d in an estimated US$130million project that will increase total capacity to 131,500 bbls/d in mid-2016 from the current 107,000 bbls/d. Aux Sable receives liquids entrained in the 2.1 bcf/d of rich gas transported on the Alliance Pipeline. It has rich-gas premium contracts with producers, most recently Encana and Brion Duvernay Gas. “Every time we do a new deal, we are acquiring more feedstock, and as we acquire richer and richer gas, that puts us in a position to expand,” said Tim Stauft, chief executive officer of Aux Stable. “We have been very successful in filling our existing plant, and now we are well on the way to filling our expanded plant.” PMC also has plans to expand its fractionation capacity, Podavin told the conference. The company currently has total C3+ inlet fractionation capacity of 205,000 bbls/d, including 65,000 bbls/d of fractionation capacity at its own facility at Fort Saskatchewan, a 21 per cent interest in Keyera Fort Saskatchewan and 120,000 bbls/d from a 72 per cent interest in its facility in Sarnia, Ont. In addition, PMC has a total of 41,000 bbls/d of fractionation capacity at a field plant in High Prairie, Alta., and plants in California, Michigan and Wisconsin, along with 5.4 bcf/d of gas processing and straddle capacity at Empress, which can produce 52,000 bbls/d of C2+ and C3+. PMC ’s Phase 1 expansion at For t Saskatchewan includes the relocation and expansion of the existing truck rack to include more propane and butane loading capabilities. It also is adding 2.5 million barrels of new brine pond capacity, two new caverns and additional connectivity to increase their fee for service storage capability. In its Phase 2 expansion, PMC is increasing the Fort Saskatchewan inlet capacity to 85,000 bbls/d from 65,000 bbls/d to assist in alleviating near-term fractionation bottlenecks, said Podavin. It also is reactivating the connection from the Peace Pipeline and a sweetening unit to handle incremental NGLs off the pipeline. Associated with the expansion, PMC will be adding a rail rack with 60 propaneloading spots and a 2.2-million-barrel brine pond as well as three new salt 10
FEBRUARY 2015 • OIL & GAS INQUIRER
caverns, two of which are custom caverns for third parties. In addition, PMC is reconfiguring its cavern allocation to allow for more spec propane plus, butane plus and condensate storage. Pembina Pipeline is another major beneficiary of the growth in liquids-rich gas production. Its Redwater West NGL system includes the Younger extraction and fractionation facility in B.C., a fractionator at Redwater, and third-party fractionation capacity in Fort Saskatchewan. Pembina will spend an estimated $415 million on twinning its existing 73,000bbl/d C2+ fractionator and a 9,000-bbl/d debottlenecking of its C 3+ fractionator. The anticipated on-stream date is in the fourth quarter of 2015.
An additional 177,000 bbls/d of liquids capacity is under construction.
A further 55,000-bbl/d C3+ expansion is planned for the third quarter of 2017, bringing total fractionation capacity at Redwater to 210,000 bbls/d. Pembina also has 7.9 million barrels of finished product cavern storage at Redwater. Pembina’s Empress East NGL system includes 20,000 bbls/d of fractionation capacity and 1.1 million barrels of cavern storage in Sarnia and ownership of 5.1 million barrels of hydrocarbon storage at Corunna, Ont. Pembina also has 2.3 bcf/d of capacity in the straddle plants at Empress. While liquids-rich production is growing, not all NGL volumes are equally valuable in the current market, and within Alberta, condensate used as diluent in bitumen currently fetches a premium. Although most condensate is removed at the field level, the Alliance gas stream contains about 0.5 per cent C5+ (pentane plus) which cannot be economically removed. At
Aux Sable that translates into a few thousand bbls/d, which is moved by rail back to Alberta, said Stauft. “It is by far our highest margin product.” According to Dean Setoguchi, senior vicepresident of liquids for Keyera, there also is a “pretty good” demand for butane, and Keyera is probably one of the largest consumers of the product in western Canada because of its iso-octane facility. Some iso-butane is used locally in refineries as a gasoline additive, while some goes to the Gulf of Mexico and California. “The weak link is propane,” he said. Continentally, inventories are much higher everywhere in North America relative to last year at this time. In Alberta, Keyera is increasing its capacity to rail out propane. Not only is there increased propane in western Canada, but the conversion and reversal of Kinder Morgan Canada’s Cochin Pipeline means that rail is the only option out, said Setoguchi. “There was 30,000–35,000 bbls/d that used to go east, and so now we have to rail that all out,” he said. “So we are building more rail-terminal capacity to rail out that product.” However, in the longer term, there could be an issue with finding markets for western Canadian propane, and Keyera is trying to find and evaluate solutions to deal with that, said Setoguchi. In Stauft’s view, the incremental market for propane is in two places: the petrochemical market and the export market, both on the Gulf Coast. Alliance/Aux Sable’s value proposition in terms of market access for the Alberta producer is to move it half the way (to Chicago), then to the incremental market where his company is pipe-connected to the Gulf Coast. Aux Sable also can move propane by pipe, truck or rail out of Chicago into the U.S. Midwest local market, which may be more attractive in the winter, said Stauft. In western Canada, in the long run, producers may need to look at export markets offshore West Coast, Setoguchi suggested. Pembina Pipeline is already looking at developing a liquefied petroleum gas (LPG) export facility in Oregon while AltaGas, which has partnered with IdemitsuKosan in a joint venture, is already exporting LPG to Asia from its Ferndale export facility in Washington state.
In The News
Most major polymer, ASP floods need $80/bbl to be worth it, says Peters & Co. By Pat Roche
Most of Canada’s polymer and alkaline surfactant polymer (ASP) floods generate an internal rate of return (IRR) of 15 per cent at an oil price of US$80/bbl, according to a new report from Peters & Co. Canadian Natural Resources’ Brintnell polymer flood would have the highest IRR at 25 per cent, Peters & Co. estimated in a 31-page research report released in December. The report provides details on seven key projects —Black Pearl Resources’ Mooney ASP flood, Husky Energy’s Taber South (Warner) ASP flood, Zargon Oil & Gas’s Little Bow ASP flood, Canadian Natural’s Brintnell polymer flood, Cenovus Energy’s Pelican Lake polymer flood, Gear Energy’s Wildmere Lloydminster polymer pilot and Northern Blizzard Resources’ Cactus Lake polymer flood. Peters & Co. said these enhanced oil recovery (EOR) projects are allowing some companies to improve recovery factors and reduce decline rates.
In a polymer flood, polymers are mixed with water and injected into oil reservoirs to increase the viscosity of the injected fluid, thereby improving sweep efficiency and increasing recoveries. In an ASP flood, other chemicals are also used. These are alkali, a caustic agent, and surfactant—in effect, detergent, which washes more oil from the rock. When caustic solutions interact with certain chemicals in crude oils, the reaction can form natural surfactants in the reservoir. Purchased surfactants can also be injected. ASP flooding, which involves several stages of chemical slug injection, is more complex than straight polymer injection. As the Peters & Co. report explained it, the ASP bank is injected first. Next, the polymer bank is injected to push the ASP bank through the reservoir. And finally, water is injected. As with straight polymer flooding, this stage is usually timed so that water breakthrough occurs near the end of the project.
“Because A SP f loodi ng not on ly improves the displacement of the oil but also reduces residual oil saturation, it can achieve higher incremental recoveries than straight polymer flooding. However, the chemicals are expensive,” Peters & Co. said. T hus, the goal is to minimize the proportion of the costlier chemicals. A l k a l i, wh ic h is relat ively c heap at about US12 cents/pound, is added to the injected f luid to reduce the adsorption—and thus the loss—of surfactant, which costs about US$2.20/pound, the report said. At the end of the project, low-cost water is injected instead of polymer, which costs about US$1–$1.50/pound. Peters & Co. said estimates and data vary for chemical costs per incremental barrel of oil recovered, but they generally range between $7 and $15 per additional barrel of oil.
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OIL & GAS INQUIRER • FEBRUARY 2015
11
JUNE 3 & 4, 2015 eXHibition Grounds | weYburn, sK
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16
th
biennial
B.C.
BRITISH COLUMBIA WELL ACTIVITY Wells licensed
Wells spudded
Rigs released
DEC/13
DEC/14
DEC/13
DEC/14
DEC/13
DEC/14
▲
▲
British Columbia
▲
Source: Daily Oil Bulletin
Painted Pony to spend $295 million in 2015 Painted Pony Petroleum’s board has approved a 2015 capital budget of $295 million, subject to review on a quarterly basis. Painted Pony intends to drill 39 (37 net) Montney horizontal natural gas wells, predominantly on its high-working-interest lands in the Blair and Townsend areas, of which 29 (27 net) wells will be on pads constructed prior to 2015. During 2015, Painted Pony intends to drill 11 wells in the Blair area, four wells in the West Blair area and four (two net) wells in the Daiber area. In the liquidsrich Townsend area, the company intends to drill 20 wells, of which 18 are anticipated to be brought on production when
PAINTED PONY TOWNSEND DEVELOPMENT PROGRAM ECONOMICS $. million to drill, complete and equip . mmcf/d IP production rate bcf P&P reserves per well , barrels P&P reserves per well bbl/mmcf liquids recovery (C3+) % internal rate of return . years payout period Source: Painted Pony
the AltaGas natural gas processing facility is completed. This facility, to be constructed by AltaGas as part of the strategic alliance with Painted Pony, is currently estimated to begin processing natural gas by the end of the first quarter of 2016. Commercial operation of the AltaGas Townsend facility is subject to regulatory and other customary approvals. Average produc t ion for 2015 is expected to be 21,500 boe/d, which will include 1,500 bbls/d of natural gas liquids. This estimate represents an increase of 59 per cent over estimated average production in 2014 of 13,500 boe/d. —DAILY OIL BULLETIN
Woodside to focus on Liard in 2015 By Richard Macedo
Woodside Petroleum’s chief executive officer Peter Coleman said the company will focus on upstream development in 2015, particularly in the Liard Basin, which is expected to supply the planned Kitimat LNG plant in which it has acquired Apache’s 50 per cent interest. Coleman said during a conference call that for Kitimat to be sanctioned, it needs to meet several internal targets, including having marketing agreements in place for a certain percentage of production. Chevron, the operator of the proposed plant, has put the percentage at 60–70 per cent of Kitimat supply under long-term agreement. “It hasn’t reached that trigger yet,” said Coleman. “I think what you’ll find over 2015 is there will be a refocusing on the activities, which have been mainly downstreambased to date—firming up the pipeline
route, fi rming up the LNG plant site. There will be a shift in focus more towards the upstream resource, really, particularly the Liard, and understanding the productivity of the upstream resource and the cost structure,” he added. “With respect to the timing of the project, no, there’s no commitment to an FID [fi nal investment decision] date at this point, there are just some prerequisites for us to get to FID.” Apache said in mid-December it was selling its interests in Wheatstone LNG and K itimat LNG, along with accompanying upstream oil and gas reserves, to Australia’s Woodside, an experienced LNG player. “It is a part of the world where costs are going to be challenged, there’s no doubt about it; it’s not the Gulf Coast of the U.S.,” Coleman said of the Kitimat
project. “These are greenfi eld sites, and it’s quite mountainous terrain to lay a pipeline across.” T he projec t needs world- c lass reserves or resources with it, and it needs the very best cost structure, he added. “Having said that, today we’re talking about prices having declined significantly on the sell side. On the cost side, though, we haven’t seen that wash through yet. Typically, there’s a nine-to-18-month lag on the cost side. “I expect over the next 12 months or more, we’ll start to see costs wash through the business,” Coleman said. “At the end of the day, it’s all about margin. It doesn’t matter if the oil price is $100 or whether it’s $20. It’s around the cost of the business, and what we need to do is develop the cost base for Kitimat that is commensurate with OIL & GAS INQUIRER • FEBRUARY 2015
13
British Columbia
“Kitimat has blue-sky potential, it’s got a long way to go, but the size of the resource and the quality of the resource and the acquisition price for us were really compelling in that regard.”
— Peter Coleman, chief executive officer, Woodside Petroleum
the price that we expect to get to maintain the margin that we need for the return.” A 50 per cent interest in the Kitimat LNG project, including approximately 320,000 acres in the Horn River and Liard Basins, adds a growth option in an emerging LNG province to Woodside’s development portfolio, the company stated. “K it i mat ha s blue -sk y potent ia l, it’s got a long way to go, but the size of the resource and the quality of the resource and the acquisition price for us
were really compelling in that regard,” Coleman said. On a presentation slide, Woodside noted that Chevron was the operator of Kitimat LNG, while Woodside would be operator of the Horn and Liard. Asked to clarify this, Coleman said, “When we say we’re operator, Apache is currently the operator of the upstream, so we’re just reflecting the current position. We expect that we’ll have some conversations with Chevron pretty soon about both
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operatorships and then some of the other development opportunities that we have around the Kitimat development, including what we do with our own Grassy Point development as well. We just need to sit down at the table and work through that. “What we’re pleased with, though, is that Chevron [is] a very competent unconventional operator in the U.S., in North America,” Coleman added. “We’re actually looking forward to working with Chevron on what’s the best operator scenario for us.”
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FEBRUARY 2015 • OIL & GAS INQUIRER
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NORTHWESTERN ALBERTA WELL ACTIVITY DEC/13
DEC/14
Wells licensed
DEC/13
DEC/14
Wells spudded
DEC/13
DEC/14
Rigs released
▼
▲
Northwestern Alberta
▲
Source: Daily Oil Bulletin
Delphi hacks back budget As a result of continued weakening in commodity price assumptions, Delphi Energy has cut its initial 2015 net capital budget by 21 per cent to between $60 million and $65 million from the previous guidance of between $77 million and $82 million, spending within forecast cash flow generated. The company plans to reduce the number of Montney horizontal wells to be drilled to six from eight, while average annual production will be four per cent lower than the initial forecast. The first two wells of the 2015 capital program are part of the previously announced Gross Overriding Royalty (GOR) agreement to partially fund the drilling of seven Montney wells in 2014 with an option to participate in three additional wells for a total contribution of $25 million. Additional GOR funding for the remainder of the 2015 drilling program is being considered. The budget is based on a WTI oil price for the year of US$70/bbl and a natural
gas price of C$3.50/mcf. Production under the revised commodity price assumptions is expected to increase approximately 12 per cent over 2014 to between 11,500 boe/d and 12,000 boe/d from a 2014 forecast of 10,500 boe/d. With the capital program entirely focused on East Bigstone, annual Montney production is expected to increase approximately 30 per cent in 2015 compared to 2014, said Delphi. The company said it is well positioned to weather the current environment given that it operates 98 per cent of its capital spending and requires only approximately four wells, or an estimated $45 million to $50 million of capital, to maintain 2015 production flat at 2014 levels. Although its Bigstone Montney project continues to generate a profit and a favourable proved producing recycle ratios in the current environment, and will continue to grow in 2015 replacing less profitable legacy production, Delphi said it remains committed to maintaining its financial flexibility by simply moderating its rate of growth.
Delphi finished drilling its eighth Montney horizontal well of 2014 at 16-27060-23W5 in East Bigstone. The 16-27 well (87.5 per cent working interest) was drilled to a total depth of 5,819 metres with a horizontal lateral length of 2,883 metres and will be stimulated with a 40-stage slickwater hybrid completion in January 2015. The drilling rig has begun operations on the first well of the 2015 program at 13-27-060-23W5. Delphi’s seventh Montney horizontal well of 2014 at 13-23-060-23W5 in East Bigstone was completed with higher sand concentrations within a 30-stage slickwater hybrid completion design. The well has produced at an average rate of 1,556 boe/d over the first 30 days with 26 per cent, or 400 bbls/d, of field condensate. The natural gas production rate of approximately 6.1 mmcf/d has exhibited minimal decline over the first 30 days of production. Additional completion design enhancements will be evaluated throughout the 2015 drilling program.
Long Run announces $165-million budget for 2015 Long Run Exploration said its 2015 capital budget will support production of 35,000– 36,000 boe/d (44 per cent oil and natural gas liquids [NGLs]) based on net capital expenditures of $165 million. The budget will be directed towards drilling and tying in low-risk, high-rate-ofreturn light oil and liquids-rich gas development wells in the Peace River Montney and Deep Basin Cardium areas. The company expects to drill around 40 wells in 2015, with an estimated 12-month capita l ef f icienc y of approx i mately
$26,000/boe/d. Development plans for 2015 include up to 15 wells in the Peace River area and up to 25 wells in the Deep Basin. L ong Ru n bega n 2014 w it h a n announced budget of $200 million and later topped that up to $285 million. Thirdquarter 2014 output averaged 34,795 boe/d (46 per cent oil and NGLs). Long Run will steward toward a sustainable model for 2015, funding its 2015 capital budget and dividend payments with funds flow from operations. Cash flow is expected
to range between $200 million and $210 million in 2015. The capital budget is based on an oilprice forecast for WTI of US$70/bbl and a natural gas price forecast for AECO of $3.50/GJ. “As it is too early to estimate the inevitable impact that lower commodity prices will have on both operating and capital costs, our guidance and 2015 capital budget do not include any benefits from potential cost reductions,” said the company. “Should commodity prices improve, the company intends to use OIL & GAS INQUIRER • FEBRUARY 2015
15
Northwestern Alberta
additional funds flow to accelerate debt repayment and improve financial flexibility.” Long Run is planning net capital expenditures of $60 million to $70 million, drilling about 20 net wells during the first quarter. It will continue a strong focus on advancing enhanced oil recovery (EOR) projects in the Peace River Montney and Redwater Viking areas, it said. In its newly established Deep Basin core area, the Pine Creek and Kakwa areas provide top-tier economics comparable with its Peace River Montney play, and the Deep Basin area as a whole contributes to substantial operational efficiencies and per-unit cost reductions, said Long Run. The Deep Basin is a key part of its 2015 capital plan, with capital expenditures of approximately $90 million (25 wells) planned for the area. The company said integration of the Deep Basin assets acquired within the Alberta Cardium trend has been successful, and it is pleased with results from initial drilling in the area. Long Run has drilled five successful horizontal Cardium wells in the Pine Creek area to date and is currently drilling the last of
six horizontal Cardium wells in the Wapiti/ Kakwa area. The first three wells drilled at Pine Creek have been producing since early fall, averaging
LONG RUN GUIDANCE Production Average: ,–, boe/d % Oil & NGLs: Funds Flow from Operations: $200 million to $210 million Capital Expenditures: $ million Dividend: $ million Basic Payout Ratio: 20% ASSUMPTIONS: WTI: US$70/bbl AECO: $350/GJ FX USD/CDN: 1.145 Source: Long Run Exploration
315 boe/d (49 per cent oil and NGLs) per well during their first 30 days, which is in line with the company’s forecast type curve. Two more Pine Creek Cardium wells were placed on production in early December with the average initial rates exceeding type-curve expectations. At Wapiti, two horizontal Cardium wells have been drilled, completed and tested at
initial rates that meet forecast type-curve expectations. Completion operations are underway at Kakwa on the fi rst two-well pad, with the second two-well pad expected to be completed early in 2015. These new Kakwa wells are to be onstream shortly after completion to take advantage of capacity Long Run has secured in a newly commissioned third-party gas plant, which was scheduled to start up in late December. Access to this additional processing capacity is expected to significantly reduce Long Run’s exposure to downtime in the Kakwa area. Long Run said its EOR projects continue to advance in accordance with expectations. Currently, the company is injecting water for pressure maintenance and enhanced recovery at two major oil plays: the Peace River Montney and the Redwater Viking. “We are excited about the potential benefits the company may see in the next 18 months from our EOR projects, including improved recoveries, lower production declines and improved capital efficiencies,” it said.
No cutbacks at Seven Generations While many producers have been cutting their 2015 capital programs, newly public Seven Generations Energy Ltd. is sticking with its initial $1.6 billion budget. “As other energy companies pare their spending plans it should reduce competition in the region, which should lead to costs savings and the potential to execute our capital plan at lower-than-budgeted cost,” said Chris Law, vice-president of corporate planning. “As currently contemplated, we have approximately $80 million of our 2015 budget which has been allocated to land acquisitions and small-scale M&A. Beyond that we have another approximately $150 million that has been earmarked for delineation and exploration of regions outside of the core drilling inventory. If we feel it prudent, we could potentially defer this investment,” Law said. Added president Marty Proctor: “We have recently heard that some operators have reduced their activity levels as a result of the lower commodity price environment. We expect this decrease in activity will 16
FEBRUARY 2015 • OIL & GAS INQUIRER
further improve our access to the best services at even more attractive pricing.” Law said the company, which recently did its initial public offering, is well-positioned to fund its program. “We presently have the majority of the IPO proceeds in cash and short-term deposits, as well as an undrawn $480 million credit facility that we will most likely be looking to increase at some point during 2015,” Law said. “We have also issued longterm debt previously and may look at doing so again in the future. A key factor in our capital investment decision-making process is our expectation that our approximate 630 well Nest 2 drilling inventory is financeable in a very low commodity price environment.” Seven Generations is focused on a single resource play, the Kakwa River project, a liquids-rich natural gas property in northwest Alberta. 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 shortlived 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 has cautioned investors it isn’t comparable to other producers by peak production rate. Seven Generations says it was braced for low commodity prices. “We planned the company right from inception with the anticipation that oversupply would lead to low prices,” CEO Pat Carlson said. “We entered the business knowing that to compete in an oversupplied environment, we would need to have low supply costs.” Fourth quarter 2014 production averaged 43,500 boe/d, up 275 per cent from the fourth quarter of 2013 and up 21 per cent from the third quarter of 2014, the company said. It cautioned that fourth quarter 2014 production figures are preliminary estimates and subject to adjustments.
NORTHEASTERN ALBERTA WELL ACTIVITY DEC/13
DEC/14
Wells licensed
DEC/13
DEC/14
Wells spudded
DEC/13
DEC/14
Rigs released
▲
▼
▲
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
Cenovus slows development By Lynda Harrison
Facing weaker oil prices, Cenovus Energy will “substantially” slow development at its next oilsands project, Narrows Lake, and cut overall capital investment by 15 per cent next year. Cenovus plans capital expenditures of between $2.5 billion and $2.7 billion in 2015, compared to an estimated $3 billion to $3.1 billion in spending this year, it announced. “The recent volatility in world oil prices is creating a challenging environment in which to set plans for 2015,” Brian Ferguson, president and chief executive officer, told a conference call held to discuss the budget. “It is the kind of price environment that demands flexibility and financial resilience.” But, he said, the company is well positioned to face the challenges ahead should the current oil price environment persist. “We expect to be able to live within our means while continuing to invest in future production growth,” he said. “We also anticipate maintaining our dividend at current levels through these difficult times.” He said the company has set a capital investment plan for 2015 that allows it to advance projects that provide production growth and shareholder value in the near and medium term. “At the same time, we expect to maintain optionality and flexibility
by continuing to invest strategically for the future, but at a moderated pace.” Cenovus is also contemplating the sale of some of its fee lands and expects to make some decisions in early 2015. The company expects total cash flow for the year of between $2.6 billion and $2.9 billion, based on a WTI price of between US$74/bbl and US$81/bbl (versus cash flow of $3.8 billion to $3.9 billion expected this year). The company anticipates moderate production growth in 2015 of approximately nine per cent for oilsands production and about four per cent for total oil volumes. The company said it will also take advantage of the slower pace of development at Narrows Lake, where it plans to spend between $60 million and $75 million in 2015, to assess its engineering and execution strategy to help ensure that the project is developed with the best possible capital efficiencies. Cenovus has integrated the 130,000bbl/d Narrows Lake project, jointly owned with ConocoPhillips, under the same management team that operates the nearby Christina Lake project. This will allow existing infrastructure and resources at Christina Lake to support the development of Narrows Lake, eliminating duplication, which is expected to lower overall costs, said Cenovus. The company expects Cenovus Capital Investment by Asset ($ millions) operating costs at Foster Budget Guidance % Change Creek to average between Foster Creek – – - $15.50 and $18/bbl in 2015, Christina Lake – – about four per cent lower Narrows Lake – – - Emerging Oilsands – – - than expected for 2014. Conventional Oil – – - Operating costs at Natural Gas – – Christina Lake are expected Refi ning – – to average between $11.75 Total ,–, ,–, - Source: Cenovus and $13.75/bbl, about six
per cent higher than expected 2014 costs due, in part, to increased turnaround activity planned for 2015. Supply costs for planned future capital investment at Christina Lake and Foster Creek, including a nine per cent return on capital, are estimated at between US$40 and US$45/bbl WTI. The company’s planned initiatives target annual operating and capital cost savings of $400 million to $500 million by 2018. It expects to reduce spending on its emerging oilsands assets, Telephone Lake
“It is the kind of price environment that demands flexibility and financial resilience.” — Brian Ferguson, president and chief executive officer, Cenovus Energy
and Grand Rapids, to between $105 million and $115 million next year. At Telephone Lake, the company has regulatory approval for a SAGD project with initial capacity of 90,000 bbls/d, expected to be developed in two phases. The company continues to view Telephone Lake as one of its most strategic future growth assets, with forecast total production capacity in excess of 300,000 bbls/d, it said. Cenovus expects to make a decision on the timing of development for Telephone Lake in 2015. At Grand Rapids, the company continues to operate a SAGD pilot project with two producing well pairs. Drilling of a third pilot well pair is planned for the first quarter of 2015. Approx imately t h ree- qua r ters of Cenovus’s planned 2015 capital program is for “committed” capital. This will be used to support the current oilsands production, the advancement of expansions already underway at the OIL & GAS INQUIRER • FEBRUARY 2015
17
Northeastern Alberta
company’s Foster Creek and Christina Lake assets, the maintenance of existing conventional oil projects and the ongoing maintenance and expansion projects at its refining assets, said the company. The remaining capital is allocated to discretionary investment, including the advancement of future oilsands assets, further development of the company’s conventional oil opportunities and technology projects. Cenovus expects to fund its committed capital of around $2.1 billion, and its anticipated dividend, with cash flow and expected available cash on hand of between $700 million and $800 million. If WTI prices are around US$65/bbl through 2015, Cenovus expects it would still be able to fully fund its committed capital for the year with internal cash flow, it said. The company anticipates discretionary capital for 2015 between $400 million and $600 million. In 2016 and 2017, Cenovus anticipates its overall committed capital to decrease to approximately $1.8 billion and $1.7 billion, respectively. The company expects to invest between $700 million and $750 million at Foster Creek in 2015. At Christina Lake, Cenovus plans to spend between $800 million and $860 million.
Due to current oil prices, the company has decided to spread capital investment in its oilsands projects over a longer period of time in order to preserve cash, it said, resulting in first production from phases G and H at Foster Creek being delayed by one or two quarters. The company anticipates fi rst oil from Foster Creek Phase G will now be achieved in the first half of 2016 and from Phase H in the first half of 2017. The company expects to bring on these approved expansion phases, including optimization, at a cost of between $35,000 and $38,000 per flowing barrel for phases F, G and H at Foster Creek. Capital efficiencies at Christina Lake phases F, G and H are expected to be between $30,000 and $32,000 per flowing barrel. Starting in late 2015, the planned optimization of the plant at Christina Lake is expected to add 22,000 bbls/d of gross incremental production capacity at a cost of between $8,000 and $10,000 per flowing barrel. This is expected to improve capital efficiencies for phases F, G and H at Christina Lake, including plant optimization, to between $28,000 and $30,000 per flowing barrel. In the year ahead, Cenovus expects oilsands growth of approximately 11,000
bbls/d net, driven largely by the Phase F ramp-up at Foster Creek, offset by an approximate 4,000-bbl/d decline in conventional oil production, partly related to the sale of a portion of the company’s Wainwright heavy oil assets in the third quarter of 2014. As a result, the company expects total oil production to average between 197,000 and 214,000 bbls/d net in 2015, approximately four per cent higher than its forecast for 2014. Over the last year, Cenovus has taken steps to improve production performance at Foster Creek. The company has improved its downhole instrumentation, enhanced steam distribution across the field, improved wellbore conformance, drilled an additional 42 wells using Wedge Well technolog y, refined well start-up procedures and debottlenecked parts of the plant. As a result, Foster Creek has experienced strong production performance in recent months, some of which is flush production from new wells using Wedge Well technology, said Cenovus. To date, in the fourth quarter, the pr oje c t h a s ave r age d ab out 67, 50 0 bbls/d net, well ahead of the company’s expectations.
Rail costs could negate savings from cheaper gas and diluent By Pat Roche
Big savings that oilsands producers will reap from lower natural gas and diluent costs will be almost wiped out if they’re forced to use rail rather than
pipeline transportation, a conference heard in December. “For every incremental barrel that cannot get on existing pipelines and for
every pipeline that isn’t constructed and you have to take rail to reach destinations, it will increase costs by about 40 per cent. You’re looking at a rail transportation cost
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FEBRUARY 2015 • OIL & GAS INQUIRER
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of almost $20 between Alberta and Europe, Alberta and India, and $12 or $13 to east Asia,” said Nicole Leonard, a Denver-based analyst at Bentek Energy, a research group. “So all those savings that oilsands producers found in lower natural gas costs, lower diluent costs, are completely negated by nearly doubling your transportation costs to market,” Leonard told a CI Energy Group conference in Calgary. While some have implied rail can replace pipelines, others maintain pipelines are as important as ever. For example, after his company’s annual meeting earlier this year, Rich Kruger, chair, president and chief executive officer of Imperial Oil, said: “You give me a choice, and I would far rather ship a barrel on a pipeline because it’s the safest, most efficient, most reliable way to move a barrel either to a refinery or to market.” T hese com ments underscore t he importance of proposed oil export pipelines, all of which face significant opposition. Bentek expects total western Canadian oil production—oilsands plus non-oilsands— to fill existing pipeline capacity in 2015. While there is more than enough rail capacity to move additional volumes, Leonard doesn’t believe rail is the most economic solution. “You’re really going to need additional pipelines—Keystone XL, Trans Mountain, Energy East and Northern Gateway. When you stack it up like this, you see that you need at least three, if not all the pipelines, to truly absorb this growing supply.” Bentek estimates rail-shipping nameplate capacity out of western Canada will reach 1.7 million bbls/d in 2017, but actual loading capacity will be closer to about 60 per cent of that. “Additionally, what’s really important to note here is that for every barrel that you have
to put on the railroad, that’s that much more congestion on North American railways. And at some point the congestion will become so great, it will no longer be economic to even rail your barrels,” Leonard warned. Bentek’s figures suggest pipelines to tidewater are the cheapest way to reach ocean-going tankers to world markets. For example, using the existing Trans Mountain Pipeline infrastructure to deliver oil to Asia-bound tankers would involve transportation costs of less than $8/bbl, and this includes trans-loading and tanker fees, Leonard said. With a new pipeline, the cost would still be less than $10/bbl. But the rail cost would be well over $12/bbl, Bentek estimated. Exporting western Canadian oil to Europe via an existing pipeline and tankers from the St. Lawrence River would cost less than $10/ bbl, while shipping via a new pipeline would cost less than $13/bbl, but rail would cost almost $20/bbl, according to Bentek. While lower world oil prices mean oilsands producers will get paid less for their oil, Bentek expects lower natural gas and diluent prices will mean significantly lower operating costs. “The last time [Western Canadian Select] had a yearly average of $60/bbl or less was 2009. And we did see a significant amount of capital moving out of the oilsands in 2009 because of that price environment. However, this time is different,” Leonard said. She expects continuing low gas prices and falling diluent prices will improve producer bottom lines. Gas fuels water boilers for steam-assisted in situ bitumen production and is used to upgrade bitumen. Diluent is in increasing demand as more bitumen is exported without being
upgraded to a lighter crude that can be pumped through pipelines. While Bentek expects the AECO price to slowly increase into the early 2020s, it forecasts the benchmark for western Canadian gas won’t exceed about $5/GJ through to 2024. Bentek forecasts the average AECO price will rise to roughly $4.50 in the next five years. Meanwhile, low Brent and WTI prices are expected to continue to push down the price of diluent. Also, western Canadian pentanes-plus, or condensate, isn’t the only hydrocarbon that can dilute bitumen. Other options include so-called natural gasoline from U.S. refineries and light crude oil. “Those barrels are going to try to compete or enter into the diluent market. They’re going to price themselves into the diluent market—based on how light they are, how much you need to dilute bitumen to pipeline specifications,” Leonard said. So while Bentek is forecasting western Canadian pentanes-plus prices between $70 and $80/bbl into 2019, Leonard suggested it could fall below $60/bbl during that period. “So we’re looking at greatly discounted diluent prices,” she said. The growth in global oil supply is occurring mainly in North America. Bentek expects North American oil production, including tight oil in the U.S. and heavy oil in Canada, to grow by more than seven million bbls/d by 2024. Bentek expects production of light crude and condensate in the U.S. will account for about 60 per cent of this growth. “However, heavy crude production is also growing, primarily from Canada. We expect heavy crude production to grow from 2.5 million bbls/d in 2014 to 4.8 million bbls/d by 2024. And that is taking into account falling California heavy oil output,” Leonard said.
OIL & GAS INQUIRER • FEBRUARY 2015
19
CENTRAL ALBERTA WELL ACTIVITY DEC/13
DEC/14
Wells licensed
DEC/13
DEC/14
Wells spudded
DEC/13
DEC/14
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Bonavista lowers spending plans Bonavista Energy’s board of directors has approved a reduction in its 2015 capital budget to reflect the current outlook for commodity prices. Bonavista’s 2015 capital budget has been revised to between $375 million and $425 million, drilling between 70 and 80 net wells. The previously announced 2015 exploration and development budget has been reduced by approximately 30 per cent from between $525 million and $575 million, and the budgeted $100 million disposition component has been removed. Not withstanding a curtailment of 3,500 boe/d in the annual guidance due to planned turnaround activity, 2015 annual and exit production is expected to grow roughly seven per cent. Annual production for 2015 is now forecast to average between 81,000 and 83,000 boe/d. This represents a two per cent reduction in annual production guidance and an 11 per cent reduction in the capital spending
pr og r a m compa r e d to Bonavista Spending Plans the previous November Region Net Wells Expenditures ($millions) 2014 guidance. West Central B on a v i s t a r e m a i n s . Glauconite committed to continuous Spirit River . Other efficiency improvements. Deep Basin In 2014, its strateg y to . Spirit River focus 95 per cent of its Other . exploration and develMontney opment program in the Total . c ompa ny ’s c or e a r e a s Source: Bonavista Energy has resulted in further enhancements to capital and operating energy sector in the near future, the comefficiencies. This has led to annual growth pany noted. of 12 per cent in the forecast 2014 exit proBonavista said it remains focused on creduction, creating a stable foundation for ating value for shareholders by consistently continued value creation in 2015. aligning the capital program and dividends In spite of a year of continued operwith funds from operations. These reducational success, the recent collapse in tions create that alignment with the recently world oil prices and the muted outlook for transformed commodity price environment North American natural gas and natural that the company anticipates operating in gas liquids pricing have resulted in a chalfor 2015, and will result in long-term lenging environment for the Canadian strength and sustainability for Bonavista.
Bellatrix again lowers 2015 spending plans Bellatrix Exploration has, for a second time, lowered its capital spending plan for 2015 to $300 million from the previous estimate of $400 million. In early December, the company reduced its 2015 planned spending to $400 million from $450 million. T he focus of the 2015 budget is t wofold: to complete construction of Phase 1 of the Bellatrix O’Chiese NeesOhpawganu’ck deep-cut gas plant at Alder Flats, and to drill high-rate-of-return Spirit River (Notikewin/Falher) liquidsrich natural gas wells, where production can be processed through the new plant.
The company’s Cardium drilling program will be tempered to focus on expiring leases and commitment wells until oil prices recover. Approximately 35 per cent of the 2015 capital budget is allocated to facilities, including the completion of Phase 1 of Bellatrix’s new deep-cut gas plant, which remains on schedule and on budget for a July 2015 start-up. The plant is designed to process up to 110 mmcf/d of gas, giving Bellatrix the ability to grow its net production to approximately 65,000 boe/d using existing strategic and third-party infrastructure.
Four per cent of the 2015 capital budget is allocated to land and seismic with the remaining 61 per cent focused on drilling. The $100-million, or 25 per cent, reduction in the 2015 capital budget from the previously announced expectation reflects a reduced drilling budget and a deferral of the timing of construction of the second phase of the deep-cut gas plant. Based on Bellatrix’s forecast capacity requirements, the on-stream date of Phase 2 of the plant can be deferred until the fourth quarter of 2016 from the original on-stream date in the second quarter of 2016 with no change in capital cost, which will then allow the OIL & GAS INQUIRER • FEBRUARY 2015
21
Central Alberta
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FEBRUARY 2015 • OIL & GAS INQUIRER
company access to approximately 80,000 boe/d of processing capacity. Along with a reduced capital budget, Bellat r i x is reducing its prev iously announced 2015 average production guidance range to approximately 47,000– 48,000 boe/d (70 per cent natural gas, 30 per cent liquids). The midpoint of the 2015 average production guidance range reflects an organic growth rate of approximately 23 per cent over the expected 2014 average daily production guidance of approximately 38,500 boe/d. Bellatrix has recently completed and placed on stream the fi rst segment of the Twin Rivers Pipeline, thereby accessing additional capacity. In addition, the booster compressor required to flow more gas at a higher pressure into its north lateral was on schedule for start up Dec. 22, 2014. These initiatives, combined with the fourth-quarter drilling program, have enabled the company to achieve its 2014 exit rate production guidance of 47,000– 49,000 boe/d.
Penn West slashes capital budget, shutting in production In response to the current commodity price environment, Penn West Petroleum says it is reducing its capital budget by approximately $215 million, to $625 million from its initial $840-million budget, and shutting in currently uneconomic production. The $215 million in capital-budget reductions reflects capital that is being deferred on longer cycle time projects, certain waterflood project capital and other non-development capital projects until oil prices improve, said the company. Much of the remaining $625-million budget will be allocated primarily toward development activities in the Cardium and Viking core light-oil areas. Despite the reduction in capital spending, Penn West has reduced its production guidance for 2015 by approximately five per cent, to a range of 90,000–100,000
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boe/d, which it attributes to the high quality of its asset base and improved reliability in production deliverability. The company initially had forecast production in 2015 of between 95,000 and 105,000 boe/d. Included in the reduced production forecast is the shut-in of approximately 2,000 boe/d of currently uneconomic production. However, based on the revised 2015 capital spending budget, Penn West said it still is forecasting production volume growth into 2016. In announcing the reduced capital spending, Penn West noted t hat in November when it announced its 2015 capital budget, the forward strip for crude oil was in the range of the company’s Canadian per-barrel modelling assumption
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of $86.50. Since that time, however, crude oil prices have declined significantly. Reflecting this reduction in the outlook for crude oil prices, Penn West has reduced its Canadian crude oil pricing assumption for 2015 by approximately 25 per cent to $65/bbl. “Penn West’s business model assumes a conservative long-run term commodity price, however, the recent downturn falls outside our lowest probabilistic expectations,” Dave Roberts, president and chief executive officer, said. “We have assured our investors that our business is strong and that we would reduce capital rather than seeking to increase production into a declining commodity cycle—focusing on profitability, not production,” he said. “The fundamental attraction of the company remains a bestin-basin light-oil opportunity across three play areas in western Canada.” According to Roberts, Penn West has the advantage of being able to adjust its spending profile across a diverse portfolio
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OIL & GAS INQUIRER • FEBRUARY 2015
23
Central Alberta
of assets to maximize its returns and focus on higher cash-returning assets in such a commodity price environment. “In addition, we have a number of other means available to protect our long-term sustainability in the event that low commodity prices persist,” he said. “Our resources are secure, our operational performance demonstrated, our future intact.” Penn West said that since November 2013, it has been working hard at building a business that can be successful in a lower commodity price environment. During that period, it has been attacking the cost structure of the business, reducing total cash costs by approximately $400 million on an annualized basis, and moving to a top quartile operator from a bottom quartile operator in each of its core light-oil operating areas, it said. The company said that in 2015 it will continue to drive costs down and expects service costs to come down signifi cantly refl ecting the impact of the lower crude oil prices.
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FEBRUARY 2015 • OIL & GAS INQUIRER
Vermilion cuts spending, shifts to gas Vermilion Energy is planning an overall decrease in spending in Canada next year and an investment shift to its Mannville condensate-rich natural gas project from its Cardium light-oil play. Development of the Cardium will continue in 2015, but at reduced activity levels compared with prior years, the company said while announcing this year’s budget. Vermilion said that despite a 22 per cent decrease in 2015 capital spending— to $525 million from an expected $675 million this year—company output will rise 15 per cent, to between 55,000 and 57,000 boe/d. “In light of the decrease in crude oil prices since mid-2014, we have reduced our 2015 capital investment plans to ensure the continued strength of our balance sheet and the sustainability of our dividend should weak oil prices prevail over a protracted period,” the company said. “Should commodity prices weaken significantly, we
have the flexibility to make further reductions in our capital program.” In Canada, Vermilion expects to drill about nine (3.9 net) Cardium wells in addition to the completion, equipping and tie-in of another 9.2 net wells drilled in 2014. In the Mannville, the company expects to drill or participate in around 30 (16.7 net) wells, a nearly 50 per cent increase from 2014. “This increase in anticipated spending refl ects the strong economics of our Mannv ille oppor tunities in the current price environment, as well as our anticipation of higher levels of partneroperated drilling proposals in 2015,” said Vermilion. “Our Saskatchewan drilling activity for 2015 is expected to stay roughly flat yearover-year at approximately eight (6.4 net) wells as we continue to improve completion results and generate strong returns on the assets we acquired in April 2014.”
SOUTHERN ALBERTA WELL ACTIVITY DEC/13
DEC/14
Wells licensed
DEC/13
DEC/14
Wells spudded
DEC/13
DEC/14
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Is southern Alberta the next big thing, asks the Geological Survey of Canada By Pat Roche
Could the next big Devonian resource play be hiding in southern Alberta? It’s not exactly tie-in time, but the Geological Survey of Canada (GSC) isn’t ruling out the possibility there might be something there. About four million to six million barrels of oil have been produced from the younger, shallower Nisku Formation at Enchant in southern Alberta. And more to the point, in this decade DeeThree Exploration made a lucrative light oil discovery in the Exshaw For mat ion, a lso ca l led t he A lber ta Bakken, at Ferguson. The Exshaw has been described as late Devonian to early Mississippian, straddling the DevonianCarboniferous boundary. “That’s obviously something that one company has been very successful at. The question remains whether or not that success can be repeated elsewhere,” said Andy Mort, a geochemist and a research scientist at the GSC in Calgary.
DeeThree’s success in southern Alberta has the GSC taking another look at the rock in the region.
While this discovery was a company maker for DeeThree, the question is whether southern Alberta could yield a laterally extensive unconventional accumulation comparable to the emerging Duvernay play of northwestern and central Alberta. The Devonian in southern Alberta has many porous and permeable reservoirs, but few known major hydrocarbon accumulations and limited exploration drilling. According to the GSC, one of the major perceived risks with this stacked carbonatedominated system is source-rock presence, quality and maturity. Past exploration has revealed source rocks and hydrocarbons generated in the Elk Point Group, Beaverhill Lake, Nisku and Exshaw/Lower Banff formations of southern Alberta, the GSC said. As well, there is associated hydrocarbon production in the Winnipegosis, the Nisku and the Lower Banff to Big Valley. There are also numerous documented oil shows and staining in the Cooking Lake, Leduc and Beaverhill Lake—but with little to no production. In the conventional era, these observed hydrocarbon indicators in sout her n Alberta didn’t generate much interest. Breakthroughs in horizontal drilling and multistage completions sparked significant interest a few years ago, but that quickly waned when only DeeThree was successful. However, the GSC and industry partners have revisited some of the results and did additional organic geochemical analysis on new samples to tackle some of the outstanding questions. W h i le t he work cont i nues, Mor t said the results have cast new light on relationships bet ween the Nisku oils
sub-families and have allowed some of the disconnects between these sub-families to be resolved. According to the GSC, geochemical analysis of extracts from cores in the Beaverhill Lake and Elk Point Group in the study area suggest that evaporitic middle Devonian source rocks, whose identity remains somewhat ambiguous, are responsible for the observed shows of migrated hydrocarbons in the intervals studied. Mort presented the findings at a Canadian Society for Unconventional Resources (CSUR) technical luncheon on Wednesday. His PowerPoint slides are expected to appear on the CSUR website once various permissions are obtained. The presentation, prepared with industry co-authors, was a synthesis of existing data and new information, and an evaluation of the remaining exploration potential of the Devonian of southern Alberta. “Just to sum up, we’ve got source rocks, we’ve got indications of source-rock prospectivity,” Mort told the well attended event. “We’re not sure how spatially extensive that is because well control isn’t great. There are other factors, such as the type of organic matter, which could have implication for the temperature at which generation is going to occur,” he continued. Mort said the existing field at Enchant could have implications for unconventional prospectivity elsewhere in southern Alberta. Also, a drill stem test at Del Bonita and a small field to the north indicated there is potential in the Winnipegosis and the Beaverhill Lake. “The problem with these evaporite carbonate systems is that they’re easy to OIL & GAS INQUIRER • FEBRUARY 2015
25
Southern Alberta
identify from their geochemical signature, but that doesn’t say anything about the spatial extent of them,” he said. Showing one slide, he said, “So here you see an excellent section in a core— 25 metres and [total organic carbons] up to 10 per cent—[but] because of the nature of deposition in such a restricted environment, it’s hard to extrapolate that spatially.... So that’s one major area of uncertainty.” The other big area of uncertainty is maturity. “We are constrained by maturity. And it’s not a simple case of just going downdip because we know that in areas which I thought were probably going to be immature, we’ve got very good production,” Mort said. “Potentially, there are maturity
anomalies which are contributing to prospectivity.” He added, “Whether we’re considering hydrocarbons that are self-sourced in place or may have migrated up, the maturity is going to be one of the things that is a fundamental control.” In an interview, Mort said the GSC has a research program that is looking at all aspects of characterization of unconventional reservoirs. “One of the elements of that is looking at areas which may have been dismissed earlier.” Sout her n A lber ta was an obv ious choice, he said, because of its accessibilit y. “We k now there’s been historically a long tradition of oil exploration. And we were just trying to look at some of t he scient if ic ev idence to suggest
that maybe there are things that have been missed. “Coming from the GSC, our interest is really in whether or not there’s a bit more to the story of the petroleum systems that we can extend from a conventional into this new era of unconventional.” In his presentation, Mort said, “The most recent interesting development [occurred] at Ferguson, and that’s the Alberta Bakken…. [It’s] potentially related to that maturity anomaly that I alluded to, but I’m not going to commit myself. I’d rather do a little bit more study. “But it’s an undeniable fact that we’ve got good oil and good production rates from the Alberta Bakken at Ferguson. And that’s a discovery that happened in 2011, showing that really southern Alberta could be seeing a new wave of interest.”
TORC budgets $125 million for 2015 TORC Oil & Gas has approved a 2015 capital budget of $125 million, which it says reflects a balance between managing longterm organic production growth, protecting the company’s strong financial position and sustaining the dividend. T he f ig ure is slight ly lower t han this year ’s current capital budget of $135 million. The company’s capital program in 2015 is primarily focused on light oil development projects with the majority of the capital directed to drilling, completions and tie-ins (approximately 85 per cent). The program is concentrated on the company’s three primary core areas of the Cardium
in central Alberta, Monarch in southern Alberta and southeastern Saskatchewan. TORC plans to drill 15 (12.8 net) wells across the company’s land position in the Cardium. With more than 290 net undrilled light oil–focused development locations identified, the 2015 budget represents approximately five per cent of this highquality development drilling inventory. TORC’s development plans for the Cardium trend represents approximately 50 per cent of the company’s drilling, completion and tie-in activity in 2015. At Monarch, TORC’s i n it ia l pla n s are to drill three (three net) development wells to continue to advance this
large emerging resource play. TORC has exposure to over 150 net prospective sections in the Monarch play. Monarch will comprise approximately 20 per cent of the company’s 2015 drilling, completion and tie-in capital budget. In southeastern Saskatchewan, TORC plans to drill 12 (six net) conventional wells representing approximately five per cent of the company’s currently identified conventional drilling locations. Southeastern Saskatchewan conventional wells are characterized by their lower-risk nature and high rates of return driven by their lower capital costs, high netbacks and the favourable royalty regime in Saskatchewan.
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FEBRUARY 2015 • OIL & GAS INQUIRER
SASKATCHEWAN WELL ACTIVITY DEC/13
DEC/14
Wells licensed
DEC/13
DEC/14
Wells spudded
DEC/13
DEC/14
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
S.K. Saskatchewan
Crescent Point cuts budget by 28 per cent Crescent Point Energy plans to spend $1.45 billion in 2015, a budget that is expected to generate average daily production of 152,500 boe/d, a nine per cent increase over 2014 guidance. The company said that with benchmark oil price volatility currently at elevated levels, the 2015 budget assumptions are conservative and disciplined. “In this commodity price environment, our 2015 budget plans are disciplined. We’ve reduced our capital expenditures from 2014 guidance by 28 per cent and we have increased our 2015 oil hedges to greater than 50 per cent at prices averaging above C$90/bbl,” Scott Saxberg, president and chief executive officer, said. “We’re forecasting nine per cent production growth over 2014, and we are starting the year strong, as we exited December with production ahead of our 155,000 boe/d guidance.” Crescent Point’s 2015 budget is also flexible. If lower oil prices persist throughout the year, the company maintains a number of levers to manage its balance sheet and dividend, including: • Strong inventory depth, which allows the company to continue high-grading drilling projects for additional capital efficiencies; • The flexibility to further reduce capital expenditures in the second half of the Crescent Point Spending Plans Play
Net Wells
Viewfield Bakken
Shaunavon
Flat Lake Torquay Uinta
TOTAL
Other
TOTAL
year, while still achieving annual average production guidance levels; and, • The option to shift more capital to its re-frac inventory and production optimization initiatives and to reduce facilities spending. When oil prices rebound, the company said it expects that it will increase capital spending. The 2015 budget assumes an initial 10 per cent reduction to service costs. Based on conversations to date with its service providers, the company anticipates that even greater cost reductions are very likely if a low oil price environment persists. “When prices fell dramatically in 2008-09, we were able to realize a 30 per cent reduction in our Bakken drilling and completions costs,” said Saxberg. “We’ll be working hard with our service providers and fully expect to see rates come down even more than they already have.” In addition to improving its capital efficiencies, Crescent Point is actively pursuing various initiatives to lower its costs. The company is also working on various drilling and completion technologies that can potentially add to production and reserves in a cost-efficient manner. Crescent Point said it has one of the strongest balance sheets in the sector, with significant financial flexibility. In addition, the company has a strong r isk ma nagement pro gram, with oil and natural % of Drilling Capital gas hedges in place until mid-2017 and early 2018, respectively. Cur rent ly for 2015, Crescent Point has more than 50 per cent of its oil production hedged, net of royalties, with an average Source: Crescent Point Energy price above C$90/bbl and
53 per cent of its natural gas production hedged, net of royalties, with an average price of C$3.60/GJ. Similar to previous oil price cycles, Crescent Point aims to use this period to further strengthen the overall position of the company. Given the strength of its balance sheet and the levers discussed above, Saxberg said Crescent Point is well prepared to weather the current commodity price environment.
“When prices fell dramatically in 2008-09, we were able to realize a 30 per cent reduction in our Bakken drilling and completions costs.” — Scott Saxberg, president and chief executive officer, Crescent Point Energy
“Oil prices have always been cyclical. We’ve been through downturns before and have not only protected our dividend and balance sheet during those times, but have come out of them even stronger than before,” he said. “We expect this cycle to be no different. We will be conservative and prudent with our capital spending, and will remain flexible to react to changing oil prices.” Approximately $1.27 billion, or 88 per cent, of the 2015 capital expenditures budget is allocated to drilling and completions, including the drilling of 616 net wells. The remaining $180 million of the budget is expected to be allocated to investments in infrastructure, undeveloped land and seismic across all core areas. As in previous years, the company’s 2015 guidance includes the assumption OIL & GAS INQUIRER • FEBRUARY 2015
27
Saskatchewan
of a lengthy spring breakup in southern Saskatchewan and the anticipated production impact of converting approximately 70 producing wells to water injection wells in the company’s waterflood programs. Crescent Point expects to spend approximately $408 million, or 28 per cent of its 2015 budget, in the Viewfield Bakken play in southeastern Saskatchewan, including drilling approximately 185 net wells. The company’s waterflood plans for 2015 include the conversion of 30 producing wells to water injection wells in the Viewfield Bakken play. The water injection conversions implemented to date have reduced decline rates and increased recovery factors in the play. In the Flat Lake oil resource play, the company plans to spend $188 million, or 13
per cent of its 2015 budget, drilling approximately 44 net wells. In the Torquay play at Flat Lake, Crescent Point said it is generating strong rates of return, even at current oil prices. The company also plans to initiate its fi rst waterflood pilot in the area targeting the Torquay zone in mid-2015. In the Shaunavon area of southwestern Saskatchewan, Crescent Point plans to spend approximately $301 million, or 21 per cent of its 2015 budget, including drilling approximately 109 net wells. The company’s waterflood plans for 2015 include the conversion of 36 producing wells to water injection wells in the Lower Shaunavon and Upper Shaunavon zones. In the Viking light oil resource play, Crescent Point plans to spend approximately
$135 million, or nine per cent of its 2015 budget, including drilling approximately 137 net wells. The increased activity over 2014 is a result of the acquisition of Polar Star Canadian Oil and Gas in the second quarter of 2014, which consolidated Crescent Point’s existing position in the area. In the company’s conventional assets in southeastern Saskatchewan, Crescent Point plans to spend approximately $129 million to drill 68 net wells. About 40 per cent of these wells are expected to be drilled on lands acquired by the company in 2014. These conventional assets offer high rates of return even at low oil prices and typically require reduced capital expenditures and no fracture stimulation to achieve high levels of production.
Raging River to spend $175 million, up production by 24 per cent Raging River Exploration plans to spend $175 million in 2015, which management forecasts should increase average production by 24 per cent. In total, the company anticipates this year’s spending to result in 165–170 net wells in an inventory of more than 2,400 locations, resulting in average production this year of 13,100 boe/d and fourthquarter 2015 production of 13,600 boe/d. The company’s 2014 capital budget totaled $275 million, with an exit production guidance of 12,750 boe/d. Raging River achieved its 2014 exit guidance during the first two weeks of December, and management anticipates fourth-quarter 2014 production to be about 12,000 boe/d, resulting in a one per cent increase in the average production guidance to 10,600 boe/d. Raging River reported a record year in which it increased production by about
5,000 boe/d and generated 66 per cent growth in production per share, accomplished without raising equity while spending cash flow and slightly increasing debt to trailing cash flow ratio to 0.8 times. The company also materially expanded its drilling inventory through continued land acquisitions and methodical stepout drilling across its asset base. In 2014, Raging River successfully tested 62 net sections previously undrilled, significantly taking the risk out of future drilling on more than 260 net sections of prospective Viking acreage, including 170 net sections tested with at least one horizontal Viking oil well. For this year, total on-stream costs represent 94 per cent of Raging River’s approved budget, while management has allocated $5 million to waterflood and facility expansion, with the remaining $5 million going
to land, seismic and maintenance capital. The company has not factored service cost reductions into its forecast, but prevailing low commodity prices should create some cost savings in 2015, said the company. Budgeting for US$60/bbl WTI this year, the board intends to review its capital budget after the fi rst quarter to determine if the expenditure levels approved for the second half of the year are consistent with the prevailing commodity prices. Despite low commodity prices, Raging River intends to continue play expansion, with about 10 per cent of next year’s drilling locations to test undrilled sections. Over the last 12 months, the company has pushed its Viking boundaries westward with the drilling of three successful exploration wells, including two in the greater Hoosier area of West Dodsland, as well as one near Provost, Alta.
Northern Blizzard lowers budget Northern Blizzard Resources said in response to the significant decline in crude oil prices that it will reduce planned capital spending for 2015 to $130 million from $215 million. The major reduction will be in the number of wells drilled, which will be cut to 74 wells, down 60 per cent from the 189 wells initially planned. 28
FEBRUARY 2015 • OIL & GAS INQUIRER
The revised capital program maintains the company’s financial strength while supporting estimated 2015 production of 23,000 boe/d (down from prior guidance of 25,000 boe/d) and the monthly dividend of eight cents per share, said the company. Northern Blizzard said that its goal is a sustainable long-term strategy that
supports per share growth and an attractive dividend. To achieve this goal in the current commodity price environment, it has reduced its 2015 drilling program, which accounts for the majority of the change in the capital program. Capital spending for the first half of 2015 is budgeted to be less than $50 million,
Saskatchewan
and this will enable it to enter the second half of 2015 in a strong fi nancial position when combined with its hedge program, the company said. As Northern Blizzard operates and controls approximately 99 per cent of its development program, it retains the ability to increase or decrease capital spending as circumstances dictate. Northern Blizzard has a hedging program that is designed to reduce revenue volatility caused by changes in commodity prices. The company has WTI hedges in place at an average price of $101/bbl for approximately 55 per cent of estimated oil production for the fi rst half of 2015 and approximately 28 per cent of estimated oil production for the third quarter of 2015. Northern Blizzard estimated the current mark-to-market value of its hedging program to be approximately $70 million. The hedging program contributes more than $5/boe to estimated 2015 funds from operations.
Whitecap cuts budget 32 per cent In response to the dramatic drop in crude oil prices, Whitecap Resources reduced its 2015 capital budget by 32 per cent to $245 million from the earlier plan of $360 million in order to maintain its financial flexibility. With the lower spending, the company has trimmed its production forecast by six per cent to an average of 37,500 boe/d (76 per cent oil and natural gas liquids [NGLs]) from 40,000 boe/d (76 per cent oil and NGLs). Forecast funds from operations will be reduced to $461 million from $584 million. Whitecap has reduced its drilling program to 99 (81.5 net) wells from 180 (145.2 net) wells in addition to deferring $12 million in facility and infrastructure capital. The majority of these reductions/deferrals have been applied in regions where they can easily be accelerated should the commodity price environment improve sooner than anticipated, it said. The revised capital program provides for drilling 53 (45.1 net) Viking horizontal wells in Saskatchewan, 11 (8.6 net) Cardium horizontal wells in southwestern Alberta, 19 (16.2 net) Cardium horizontal wells in Pembina, eight (7.5 net) Dunvegan horizontal wells in northwestern Alberta and eight (4.1 net) horizontal oil wells at Boundary Lake in B.C. The re-alignment of its 2015 capital program allows it to focus on the most profitable projects with the highest rate of return within its extensive inventory of drilling location, said Whitecap. The revised capital program also balances the need for quick well payouts along with strategic initiatives that are important to the company’s long-term sustainability, it said. The revised budget is based on a WTI price of US$65/bbl (previously $85/bbl), an Edmonton par diff erential of $7/bbl ($6/bbl) and C/US exchange rate of 85 cents (previously 88 cents). It also assumes an AECO gas price of C$3.25/GJ (down from $3.80). The company also has developed forecasts under additional price assumptions. The company has hedged 61 per cent of its crude oil production at C$98.61/bbl for the first half of 2015 and 41 per cent of production at $97.15/bbl for the second half of this year.
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OIL & GAS INQUIRER • FEBRUARY 2015
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Cover Feature
DESPITE LOW PRICES, DUVERNAY DRILLING EXPECTED TO REMAIN STEADY By Darrell Stonehouse
30
FEBRUARY 2015 • OIL & GAS INQUIRER
Cover Feature
W
ith oil prices cut in half in six months and gas prices hovering around the $3/ GJ mark in early January, there isn’t much to be happy about in western Canada’s energy sector. Capital expenditures are being cut and drilling rigs idle as the industry hunkers down to wait out the storm. There are, however, plays across the basin where drilling continues, and one of those bright spots is the Duvernay in central Alberta. Major players in the Duvernay like Encana, Talisman and Apache made significant progress in proving up their land base and drilling and completion strategies in 2014, and are looking to further advance the play in 2015. A few smaller players with large land holdings in the Duvernay, including Canadian International Energy and Athabasca Oil, are also investing heavily in drilling and completions this year. Encana plans to spend between $250 million and $350 million this year in the Duvernay. It will continue to accelerate development in the Simonette area, where it expects to run about three to five rigs and drill 15–25 net wells. An additional $800 million is expected to be invested in the play through Encana’s joint venture with Brion Duvernay Gas (formerly named Phoenix Duvernay Gas), representing a gross investment of between $1 billion and $1.2 billion. Encana expects its net liquids production from the Duvernay to grow by about 200 per cent to average 6,000–7,000 bbls/d in 2015. In the Simonette area, Encana will be focused on completing two eight-well pads and one nine-well pad and successfully bringing them on stream, Encana president and
chief executive officer Doug Suttles told analysts in December. “Completion activities should be finished on the nine-well pad by mid-January and on the first of the eight-well pads about a month later. We then expect to bring on the third eight-well pad by the second quarter,” he said. Suttles said Encana reduced its Duvernay drilling costs by about 40 per cent in 2014, compared with 2013. “We expect two new midstream facilities to support our planned growth to come online in the second half of 2015, bringing our total capacity to 150 mmcf/d of natural gas processing and 30,000 bbls/d of condensate handling,” he added. “We have secured additional firm transportation capacity on the Alliance Pipeline and Aux Sable’s deep-cut facility, which ramps up over time, matching our rich-gas growth profile,” he said. “For our condensate volumes, we have secured firm capacity on the Pembina Peace Pipeline for transport to Fort Saskatchewan, [Alta.].” The company’s 2015 capital budget assumes a price of $70/bbl for WTI crude and a NYMEX gas price of $4/mmBtu. Asked where the company will cut its capital program if WTI averages less than $70/bbl, Suttles declined to say. “We’ll adjust our capital as the year progresses,” he replied. Encana said its Duvernay assets have average supply costs of about $35–$55/boe and are capable of delivering quality returns amid lower commodity prices. Talisman Energy also advanced its Duvernay development in 2014. The company, in the midst of being
taken over by Spanish oil giant Repsol, has yet to release its Duvernay plans for 2015. But given its success last year, the Duvernay assets appear to be a keeper for Repsol. In November, Talisman Energy president and chief executive officer Hal Kvisle said the company is “excited” about the liquids-rich potential of the Duvernay, and reducing costs in the play will continue to be an area of focus for the producer. In the Duvernay, two Ferrier wells in the company’s southern acreage were completed in the third quarter, and a Bigstone well in the North Duvernay drilled in the first quarter was completed and brought on stream, the company reported recently. “Talisman holds extensive and very attractive acreage in the South Duvernay, and our two Ferrier tests confirm that we have very liquidsrich acreage in Ferrier,” Kvisle said. The Bigstone well, meanwhile, recorded a 24-hour raw gas test rate of 11.3 mmcf/d of gas and 670 bbls/d of wellsite liquids. This well is now on stream but will be produced at lower rates while the company debottlenecks liquids-handling facilities at its Bigstone plant. “We drilled and completed our most recent Duvernay wells with 2,000-metre horizontal laterals with 20-stage fracs of 140 tonnes of sand per stage,” Kvisle said. “We plan to increase frac tonnage substantially in our upcoming completions. “We’ve also piloted the ball-drop completion technique on the second Ferrier well, which reduced our completion costs by approximately 30 per cent. We’re now looking into expanding this method to more of our operations in the Duvernay.” Later this year, the company will begin drilling on its
OIL & GAS INQUIRER • FEBRUARY 2015
31
Cover Feature
liquids-rich Waskahigan and Pine Creek acreage. “We’ll also leverage our infrastructure in Edson, [Alta.,] to service our northern Duvernay position,” Kvisle said. “The challenge in the Duvernay is cost reduction; we expect to get our cost structure down to $10 million to $12 million per well over the long term. “We’ve made significant progress already with our best wells running in the $15-million range,” with improvements expected to come from larger programs with multiwell pads. Kvisle laid out a couple of different scenarios in terms of Duvernay development, depending on commodity prices—one would see Talisman aggressively develop 80 per cent of the acreage. “We’d be getting into some of the lesser attractive acreage if we did that,” he said. “If we were running a program of approximately that magnitude, that’s capital north of $1 billion
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FEBRUARY 2015 • OIL & GAS INQUIRER
a year, and that kind of a program could go on for five to 10 years. “Under the right commodity price environment, for the Tier 1 plus Tier 2 acreage of the Duvernay, you might see us develop something approaching 240,000 acres of that total position, and to make that make sense, you’d have to see stronger gas prices because some of that acreage is prolific, but it’s dry gas, or relatively dry gas.” On the other hand, he pointed to areas like Waskahigan, Ferrier, Bigstone and Pine Creek where 80 per cent of the acreage is highly attractive, even at today’s prices. “In that scenario, you might see us spend half as much capital… maybe $400 million a year just to focus on those core areas,” he said. “In the more focused program, in just the very best of our Tier 1 acreage, we are considering whether we might go that on our own in order to maximize value for Talisman.” Canadian International Oil (CIOC) has drilled one of the best oil
wells in the Duvernay. In December, CIOC reported a peak 24-hour production rate of 1,528 boe/d from the 13-01 Duvernay horizontal pilot well comprised of 1,446 bbls/d of oil and 494 mcf/d of gas. CIOC kicked off a Duvernay drilling and pilot program in the Simonette, West Ante Creek and Karr areas as the company continues to progressively de-risk its extensive land base with the drilling of vertical strat/core wells and a horizontal pilot. The company said its land base in the Duvernay fairway is proving to be highly prospective as the majority of the acreage lies within the high pressure condensate window with strong net to gross ratios. “We are extremely pleased that our first horizontal Duvernay pilot well has proved our technical assumptions on the viability of the liquids-rich Duvernay fairway moving west of the Kaybob area,”
Photo: Aaron Parker
Encana and its partner Brion expect to spend between $1 billion and $1.2 billion in the Duvernay in 2015.
Encana Duvernay Key Statistics Land (net acres)
Cover Feature 250,000
Average Working Interest
50%
RPH Type Curve EUR/Well
1,000–1,200 mboe
RPH Type Curve ROR
>90%
Well Inventory (gross)
1,400–1,450
RPH Well Costs (DCT)
$12 million to $20 million
Royalty Rate
5–15%
2015 Forecast Production (net) Natural Gas 2015 Forecast Capital (net)
2015 Forecast Wells 2015 Forecast Rigs Supply Cost RPH: Resource Play Hub
30–35 mmcf/d $200 million to $250 million, $1 billion to $1.2 billion gross 15–25 net, 30–50 gross 05-Mar <$1.00/mcfe, $30–$60/boe
Source: Encana
Supply Cost is flat NYMEX/WTI price that yields an IRR of nine per cent without land or G&A costs
said Scott Sobie, president and chief executive officer. “The result provides us with an additional contiguous development horizon over a significant acreage base that complements the robust Montney development potential on our lands.” The 13-01 well had a peak 24-hour average rate of 1,528 boe/d at a restricted flowing pressure of approximately 27 mPa. The well had recently been tied-in and is currently on production and will continue to be produced at a restricted oil rate for reservoir management purposes. During the last seven days of reported production, the well averaged a restricted rate of 912 boe/d consisting of 828 bbls/d of oil and 506 mcf/d of natural gas. The company is very encouraged with this test given that the completed interval was only 1,182 metres and future development wells are anticipated to have over 1,500 metres of stimulated lateral.
The company expects to exit 2014 with over 199,000 net Duvernay acres (100 per cent working interest). The company is establishing regional play continuity with the drilling of an additional six Duvernay vertical test wells. Athabasca Oil plans on spending $135 million for Duvernay drilling and completions in 2015. The program includes 11 Duvernay wells (nine horizontals) with four rigs currently targeting the play. The primary objectives of this program are to add near-term production and cash flow at Saxon and Kaybob West and to retain Duvernay lands that are prospective for commercial development into the intermediate term. Athabasca says about 95 per cent of its core 200,000-acre Duvernay land position at Kaybob will be held into the intermediate term at the end of the winter drilling program. As the program meets
all of the company’s near-term landretention objectives, Athabasca has significant flexibility to adapt its light oil capital plans during the year to respond to market conditions and technical learnings. Apache plans on spending around $400 million in Canada in 2015, with the majority targeting the Montney and Duvernay. “We have a plan for 2015 that is really going to move forward two liquids-rich opportunities in the Montney and Duvernay, and they’re going to be big growth drivers for us going forward, really, in 2016, 2017 and beyond,” John Christmann, chief operating officer for North America, says. Apache has 177,600 net acres in the Duvernay at Kaybob and plans on using two rigs to drill 17 horizontal wells in its inventory of 1,700 horizontal locations for the Duvernay in 2015. Apache, which underwent a significant reorganization in 2014 to
OIL & GAS INQUIRER • FEBRUARY 2015
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Cover Feature
focus on high-return resource plays in North America, is now in the process of driving down costs in Canada by leveraging knowledge gained in U.S. shale plays. “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 asks. According to Navneet Behl, vice-president of operations for unconventional resources, in order for Apache to become a premier resource company for North American unconventional plays, it must improve recoveries and minimize costs, which is the impetus for its supply chain initiatives. “On the supply chain side, you look at equipment, sand, chemicals and water,” he says. “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
GIBSON ENERGY
you have everything lined up here. These are your major constraints and your major costs that will change the face of the play.” In the Permian Basin, for example, Apache has secured a dedicated fleet of sand-hauling trucks and expects to add more in 2015, reducing non-production time rated to sand by 80 per cent and saving as much as US$120,000 per well. The company is working on several more initiatives that will enable approximately 10 per cent more cost savings within North America. Behl says, “We have taken this to Canada, and we are working with the Canadian region on the Duvernay play to source our sand and related equipment, and with that we expect a savings of about $1.8 million per well in 2015.” In the Duvernay specifically, Apache has two rigs drilling a seven-well pad, testing six and
eight wells per section with onemile laterals. The company will test a 1.5-mile lateral in the Duvernay in 2015. “The key to Canada, though, is attacking the cost structure,” Christmann says, adding that the company is confident it can remove $5.1 million from the cost for completions on Duvernay wells up front, taking more of an unconventional approach with fluid systems. He notes that with the winteronly drilling that can occur in western Canada, by moving completions to spring, the company can save money on the cost of heating up water. “So we anticipate our costs to be in the $13-million range this year, and I think as we continue to integrate the supply chain…there are additional costs we could drive out of the system. We see, going forward, that we can take these costs to under $12 million.”
w w w.g i b s o ns . co m
Gibson Energy is a growth-oriented, solutions-based, North American midstream energy service company with an integrated portfolio of businesses.
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FEBRUARY 2015 • OIL & GAS INQUIRER
Feature
Heavy oil producers look to tough out price collapse By Darrell Stonehouse
or the last five years, heavy oil operations have been the darling of many operators’ portfolios, providing the highest returns of any play type in western Canada. Not anymore. The collapse of global oil prices, combined with a stubborn differential for Western Canadian Select (WCS) heavy blend, has prices for heavy oil hovering around $33/bbl. The oil price rout has higher-cost operators cancelling drilling plans and shutting in production, while lower-cost operators continue with long-term developments and high grade their portfolios. The big players in heavy oil are taking a cautious approach to 2015. First the good news. At Husky, it’s full steam ahead on its array of small SAGD projects currently under construction. In mid-December, Husky announced it planned to spend around $1 billion on its heavy oil portfolio. OIL & GAS INQUIRER • FEBRUARY 2015
35
Feature
140
-18.68
-22.19
-19.66
80
-18.59
100
WCS ($US/BBL)
-13.74
WTI ($US/BBL)
120
break down where the drilling cuts would come from, the majority of these wells are heavy oil wells. Baytex Energy is planning on focusing its 2015 spending on the Eagleford shale play in Texas, while reducing expenditures in Canada. Approximately 23 per cent of the 2015 capital budget will be invested in Baytex’s heavy oil operations at Lloydminster and Peace River, Alta. At Peace River, the capital budget includes the drilling of approximately 14 horizontal multi-lateral wells and 12 stratigraphic and service wells. At Lloydminster, the company plans to drill 32 net development wells, of which approximately 65 per cent will be horizontal wells. Twin Butte Energy says it is responding to lower oil prices by shrinking its previously announced capital budget for 2015 to $120 million from $160 million. The company also said it is selectively shutting in approximately 1,000 bbls/d of its historic higher-operating-cost heavy oil production, which will not generate positive cash flow at a WTI price of $60/bbl. “The industry has seen a significant drop in oil pricing over the last seven weeks, which, even with Twin Butte’s strong hedge position, could negatively impact the company’s cash flow for 2015,” Twin Butte said. The first-half 2015 capital plan of $55 million will focus on following up secondhalf-2014 Sparky, Dina-Cummings and Lithic-channel drilling. The program features drilling a total of 26 wells (21 at Provost, five on heavy oil
60 40
DIFFERENTIAL%
-16.05
contingent resources to be 1.9 billion barrels, of which 54 per cent, or one billion barrels, has the potential to be recovered using thermal technology. “Our heavy oil business has undergone a complete transformation, and this assessment confirms we have more room to run,” Ghosh said. “We have recovered approximately 950 million barrels of oil from the Lloydminster region over almost 70 years and current technologies, such as our thermal developments, are allowing us to extract even greater value from this vast resource.” The best estimate contingent resource of 1.9 billion barrels is an increase from the 107 million barrels booked at the end of 2013, as the previous assessment took into account only projects that were well advanced toward development. Heavy oil initially in place and resource estimates have an effective date of Dec. 31, 2013. The Lloydminster block spans approximately 37,000 square kilometres, with more than two million net acres to Husky and more than 4,000 producing wells. In November, Canadian Natural Resources (CNRL) said it was spending $1.1 billion on its heavy oil properties, including the drilling of 732 net primary heavy oil wells in 2015. Primary heavy oil production was expected to be comparable to forecast 2014 levels, ranging between 144,000 and 147,000 bbls/d. But in mid-January, CNRL threw those plans out the window, cutting its overall budget by $2.4 billion and shelving plans for 650 wells. While the company didn’t
-12.94
Company chief executive officer Asim Ghosh said Husky’s spending plans are based on an assumption of US$55/bbl for WTI crude in the first half of 2015 and US$65 in the second half of the year. In its thermal heavy oil operations, assuming a flat $60 WTI oil price over the life of the projects, the company said the full-cycle rates of return are about 15 per cent. Husky has rejuvenated its legacy heavy oil business over the past four years through thermal developments. Thermal production has risen to 45,000 bbls/d in 2014 from 18,000 bbls/d in 2010 and is slated to rise to 80,000 bbls/d by the end of 2016. In Saskatchewan, the 10,000-bbl/d Rush Lake thermal oil project is to flow first oil in the third quarter of 2015. The 10,000-bbl/d Edam East thermal oil project is slated for first oil in the third quarter of 2016, the 3,500-bbl/d Edam West thermal oil project is scheduled to start producing in the fourth quarter of 2016, and the 10,000-bbl/d Vawn thermal oil project is also scheduled for first oil in the fourth quarter of 2016. Husky undertook an evaluation of its heavy oil resource in 2014, and the news was good. An independent assessment of Husky’s heavy oil resources in the Lloydminster, Alta., region has significantly increased the company’s overall working interest of total heavy oil initially in place estimate to 17 billion barrels, of which 16 billion barrels are discovered heavy oil initially in place. Conducted by Sproule Unconventional, the assessment has also estimated Husky’s working interest of best estimate
20 0 JUNE
JULY
AUGUST
SEPTEMBER
OCTOBER
NOVEMBER
DECEMBER Source: Baytex Energy
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FEBRUARY 2015 • OIL & GAS INQUIRER
Feature
Thermal heavy oil projects are continuing through the downturn in prices.
assets) and the construction of three new facilities at Provost to enhance oil processing and water-handling capacity and decrease long-term decline. These investments will position the company to accelerate activity and increase output when commodity prices improve, said Twin Butte. The company said its current hedge position for 2015 is providing significant protection for 2015 cash flow with 11,750 bbls/d hedged for the first half at over $80 WCS based on WTI of about $100/bbl and 6,000 bbls/d for the second half of 2015 at $79.67 WCS. BlackPearl Resources expects 2015 capital spending to come in at $71 million, $40 million carrying over from 2014, and $31 million in new spending. In 2014, the company spent $240 million. The 2015 budget includes completion of the Onion Lake, Sask., SAGD project, which will account for 80 per cent of expenditures.
Thermal development at Onion Lake is expected to use a combination of traditional SAGD (two horizontal wells about five metres apart) and a modified SAGD process (using existing and new vertical wells as steam injectors and horizontal producer wells). At Onion Lake, construction of the first 6,000-bbl/d phase of the SAGD project continues, including delivery of more than 35 per cent of the modules for the central processing facilities by the end of the third quarter. Drilling of the horizontal production wells and vertical injector wells also began during the quarter. BlackPearl said the project remains on budget and on schedule to start steam injection in mid-2015. At the end of September, 42 of 115 modules of the central processing facility were delivered to the project site and six of 12 horizontal producer wells were drilled. Also, seven of 19 vertical injector wells and three water disposal wells were drilled
during the quarter. The remaining wells to be drilled were expected to be completed by year’s end. BlackPearl has also begun construction of the 27-kilometre water source pipeline to bring source water to the steam generation facilities. Currently, there are more than 100 construction workers on site. Gear Energy Ltd. has joined the long list of heavy oil companies that have altered 2015 capital expenditure plans, as the company announced in late January it is taking a “conservative approach” to firsthalf spending. For the short term, the company’s capital program will be limited to $3 million to focus on completing and bringing on production two dual lateral wells at Morgan and performing selective re-completion and optimization projects. Gear plans to dedicate excess cash flow to pay down net debt by an estimated $20 million during the first half of 2015. The company will also shut-in an additional 350 bbls/d of high-cost production resulting in increased net cash flow. The revised production estimate for the first half of 2015 is 6,400 boe/d. “Given the current weakness and uncertainty in the future price of oil, Gear has adopted a conservative approach to its capital program for the first half of 2015. At this time, the future price of oil is much higher than the current spot price based on forward strip pricing,” the company said. “We believe that returns on our existing inventory of drilling locations can be materially improved by delaying investment until we see the spot price of oil improve along with a significant reduction in service costs.” In November, Gear announced its initial 2015 capital budget of $95 to $105 million. This budget was based upon a West Texas Intermediate price of US$80 per bbl and a Gear realized price of C$65 per boe. Two months later, Gear’s estimated realized price has been reduced to under $35 per boe. “We expect that the current depressed prices across the industry will go a long way to re-balance supply and demand and ultimately bring the price of oil back to a more sustainable level,” the company said. “Fortunately, Gear has no material land expiries or drilling commitments and by focusing on reducing net debt will have the ability to remain flexible in planning capital spending to maximize value for the long term.” OIL & GAS INQUIRER • FEBRUARY 2015
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FEBRUARY 2015 â&#x20AC;˘ OIL & GAS INQUIRER
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