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Energy & Mines

December 2018

BC Land Sales

Alberta Land Sales

Canadian Natural Resources Limited

Alberta’s Oil Cuts

ATCO Awarded Modular Supply Contract

ATCO Wins Workforce Housing Contract

Westcoast Spruce Ridge Program


Pembina Capital Spending

Wells Licensed

BC Land Sales

British Columbia wrapped up its 2018 land sale schedule with a $496,342 auction.

Industry picked up 538 hectares at an average price of $922.57.

The province ended the year with $64.13 million in bonus revenue, driven largely by the June sale which attracted $42.08 million. Landsolutions GP Inc. picked up a 1,847-hectare drilling licence in B.C.’s June land sale for $42.05 million. The parcel produced a per-hectare price of $22,767.84.

Industry acquired 69,980 at land sales in B.C. for 2018 at an average of $916.39.

For 2017, the province attracted $173.25 million in bonus bids on 79,238 hectares at an average price of $2,186.49.

JuneWarren-Nickle's Energy Group

Alberta Land Sales

The Alberta government closed its books on 2018 with a solid $48.86-million land sale.

Industry purchased the rights to 121,390 hectares at an average price of $402.49.

The government closed 2018 with $411.38 million in bonus bids on 1.39 million hectares at an average of $296.84. Last year, a bounce-back year after an anemic 2016, the province collected $556.39 million on the sale of 1.48 million hectares at an average price of $374.91.

JuneWarren-Nickle's Energy Group

Canadian Natural Resources Limited

By Deborah Jaremko

Canadian Natural Resources Limited is planning a dramatic reduction in drilling next year in a constrained budget that it says could be increased if market access improves.

The company will drill just 97 wells in 2019 compared to 516 in 2018, an 81 per cent reduction year-over-year.

Analysts with GMP FirstEnergy noted this includes zero thermal wells compared to 126 in 2018, a 70 per cent reduction in Canadian light oil wells, a 77 per cent reduction in primary heavy oil wells, and five net natural gas wells versus 15 in 2018.

Despite the company's massive decrease in drilling activity, and production curtailments now mandated by the Government of Alberta, Canadian Natural expects its 2019 exit rate to increase by three per cent compared to 2018, at 1.085 million to 1.174 million boe/d.

Canadian Natural plans to spend a total $3.7 billion in 2019, down from $4.6 billion this year. The company could increase the budget to $4.4 billion if market access improves.

JuneWarren-Nickle's Energy Group

Alberta’s Oil Cuts


(Reuters) —  Alberta's decision to mandate output cuts to reduce a supply glut will have negative effects on North American producers of lighter oil used for blending and U.S. refiners importing crude via rail, even as several major Canadian energy companies cheered the move.

Canada's oil production is at a record 4.6 million bbls/d, but producers cannot get oil to market because the pipelines that cross into the United States are full. Pipeline construction, particularly in Canada, has not kept up with record output.

Shippers and refiners are moving discounted bbls of oil via rail or trucks, but the storage glut sits at more than 35 million bbls in Alberta, just below all-time records set in September, according to data firm Genscape.

Oil prices have been sagging, with U.S. crude recently dipping to near $50/bbl on renewed oversupply fears. Canadian producers have been hit even harder because of the hefty discount.

Alberta’s government ordered producers to cut output by 8.7 per cent, or 325,000 bbls/d starting in January. That boosted Canadian crude prices and shares of major producers, but has had negative effects elsewhere.

Demand for condensate, is expected to fall as producers cut heavy output, analysts say. A narrowed discount for Canadian crude prices makes rail shipments to the Gulf Coast less economic for refiners.

Stronger per-bbl pricing will help Canadian companies increase capital spending in preparation for 2020, when more export capacity is set to come online.

JuneWarren-Nickle's Energy Group

ATCO Awarded Modular Supply Contract

ATCO has entered into a joint venture with a subsidiary of Bird Construction Inc. to design, engineer and construct a 4,500-person workforce accommodation centre, known as the Cedar Valley Lodge.

The facility will be built to house workers involved in the construction of LNG Canada’s natural gas liquefaction and export facility. The Bird-ATCO joint venture will execute a modular supply contract for 4,500 accommodation rooms for the Cedar Valley Lodge Project through a joint venture between ATCO and the Haisla Nation. Design and engineering for the project is currently underway, with construction commencement planned for spring 2019.

The project is one of the largest accommodation facilities ever built in Canada and will provide high quality amenities for the LNG Canada workforce, the company said. ATCO has executed several operational support services contracts and modular site accommodation projects within the Kitimat region. Since 2011, the company has operated a successful joint-venture partnership with the Haisla Nation, which will also benefit from the Cedar Valley Lodge project.

JuneWarren-Nickle's Energy Group

ATCO Wins Workforce Housing Contract

ATCO, as operator for its joint-venture partnership with the Haisla First Nation, has been chosen to provide workforce housing and operational support services for three camps in the Haisla territory in support of construction of the Coastal GasLink pipeline in British Columbia.

The contract was conditionally awarded by Coastal GasLink Pipeline Ltd. upon a positive final investment decision (FID) by the joint-venture partners of LNG Canada, and has a combined value of approximately $40 million.

The three camps are proposed to commence operations in March 2019 and continue until August 2022. ATCO has operated a successful partnership with the Haisla Nation since 2011, delivering multiple camp and modular site accommodation projects within the Kitimat region of British Colombia.

JuneWarren-Nickle's Energy Group

Westcoast Spruce Ridge Program

By Elsie Ross

Following a public hearing, Westcoast Energy Inc. has received regulatory approval with 22 conditions for the construction and operation of the $564.5 million Spruce Ridge program in northeast British Columbia.

The Chetwynd Loop consists of approximately 25 kilometres of 36-inch outside diameter pipeline. Approximately half the loop will parallel existing pipeline right-of-way, with approximately 12.5 kilometres proceeding through a greenfield route east and south of Chetwynd, away from developed areas.

The Aitken Creek Loop is comprised of approximately 13 kilometres of 24-inch OD pipeline, all to be located on Crown land, with the majority of the loop running parallel to existing linear disturbances. It would commence at the existing Westcoast Aitken Creek Gas Plant, approximately 103 kilometres northwest of Fort St. John, and end just west of the existing Spectra Energy Midstream Corporation Highway gas plant, approximately 109 kilometres northwest of Fort St. John.

The project also includes the installation of two additional compressor units at the existing Compressor Station N5, approximately 27 kilometres northwest of Hudson’s Hope and at CS 2 approximately 47 kilometres south of Hudson’s Hope. Minor modifications also are planned at CS N5 and at CS 16, approximately 48 kilometres south of Fort St. John.


Westcoast said the project will enable it to provide service for the expansion firm transportation service agreements from receipt points along the Fort Nelson Mainline for gas deliveries to the NOVA Gas Transmission Ltd. (NGTL) system at Compressor Station 16 (Sunset); and from receipt points along the Fort St. John Mainline for gas deliveries to the Westcoast T-South system at Compressor Station No. 2, providing access to markets in B.C., the United States Pacific Northwest and California.

As a result of an open season in September/October 2016, Westcoast received bids from, and subsequently entered into expansion service agreements with, shippers for 402 mmcf/d of incremental firm service with a weighted average term of approximately 24 years.

Shippers awarded expansion service who held existing firm service in Zone 3 were required, under the terms of the open season, to extend the term of their existing service, up to an amount equal to the volume of expansion service awarded, to match the minimum 10-year open season term requirement for expansion service, said Westcoast. This resulted in a term extension being applied to 200 mmcf/day of existing firm service.

JuneWarren-Nickle's Energy Group


By Elsie Ross

After a hiatus of more than two years, PETRONAS Energy Canada Ltd. is back in the field in northeast British Columbia, as it begins drilling to underpin its share of natural gas for the LNG Canada export project.

However, the former Progress Energy Canada Ltd. has no plans to return to the frenetic pace of 2013-2014 when it was running nearly 30 rigs continuously in the area.

This time around, the pace will be more measured with the company looking at 40 years of steady rational development in northeast B.C.

PETRONAS Canada started with one rig in October of this year and will add a second one at some point in 2019. It envisions gradually building up to four to six rigs and a couple of hydraulic fracturing spreads for the next 30 plus years as it develops its 60 tcf of recoverable resources.

The company is currently drilling the fourth well on its first “start-up” pad and the second well is already faster than any of its other 600 Montney wells. Current net production is just under 70,000 boe/d and PETRONAS expects that to double to 140,000 boe/d over the next five years in a measured steady ramp up to an LNG Canada onstream date in 2023/2024.

Formed in the early 2000s, Progress Energy spent the following few years acquiring land in northeast B.C. north and west of Fort St. John and building a land position. In the 2011-2012 period, it shifted to proving the resource and PETRONAS became involved, first as a joint-venture partner and then as the owner of the company.

Between 2012 and 2015, PETRONAS was very much focused on delineating the resource with an LNG project clearly in mind as it drilled a grid of wells across the land base.

The company drilled three-mile grid drilling pads with each pad typically having three wells — an Upper, Middle and Lower Montney. The wells were drilled with similar lateral lengths, well designs and completion techniques.

However, what that meant was that while PETRONAS started with a state-of-the art well design in 2013 and 2014, due to rapid changes in the industry its new wells will be very different from those delineation wells, he said. The current well design is a 2,600 metre lateral with about two tonnes per metre of proppant. Although the company feels that is the “sweet spot,” it will continue experimenting with that, the session heard.

PETRONAS also has begun construction of two gas plants in the heart of its Montney lands and significant pipeline infrastructure needed to connect those plants with some of its existing compressor stations.

In the wake of lower natural gas and LNG prices, the company paused between 2016 and 2018 to reset its strategy, figuring out how it could monetize its resources. PETRONAS had been working on its own LNG plant at Prince Rupert but opted not to proceed, deciding instead to participate as a partner in the Royal Dutch Shell plc-led LNG Canada plant at Kitimat.

PETRONAS commitment

PETRONAS is “very, very committed” to Canada with its North Montney position the second largest position in its worldwide portfolio. The company wants to grow its unconventional portfolio and its Canadian assets represent the largest unconventional element in its portfolio.

PETRONAS has nearly 1.5 million gross acres in northeast B.C., of which about 900,000 gross acres are Montney rights. It also has about 800 active wells of which just over 600 (about three-quarters) are Montney producers. In addition, the company has four gas plants, 33 compressor stations to feed the plants and about 3,200 kilometres of operated pipeline.

JuneWarren-Nickle's Energy Group

Pembina Capital Spending

Pembina Pipeline Corporation says it has allocated $900 million (53 per cent) of its 2019 capital program of $1.6 billion to its Pipelines division with another $425 million (25 per cent) to be spent on facilities.

The budget for pipelines includes spending associated with the Phase VI and Phase VII expansions of the Peace Pipeline System, both of which are currently underway and anticipated to be in service in the second half of 2019 and the first half of 2021, respectively.

Also included are funds directed to completion of the northeast British Columbia Montney infrastructure and the Wapiti condensate lateral both of which are expected to be in service in the second half of 2019.

Additional capital will be spent relating to previously known and anticipated final cleanup costs along the Peace Pipeline right-of-way, as well as communication and SCADA infrastructure upgrades.


In the Facilities division, Pembina plans to spend $210 million on the development of Duvernay II & III which includes gas processing, condensate stabilization and related infrastructure under the previously announced 20-year infrastructure development and service agreement with Chevron Canada Limited. Duvernay II & III are expected to be in service in mid- to late 2019 and mid- to late 2020, respectively.

Additional spending will be directed towards progressing the Prince Rupert LPG Export Terminal, the Empress expansion and the recently announced Hythe developments project.

Joint venture working interest capital

Pembina's 2019 capital budget includes $205 million (net to Pembina), or 12 per cent, to be invested in projects within the company's joint venture partnerships including primarily Veresen Midstream Limited Partnership and Canada Kuwait Petrochemical Corporation.  Of the $205 million of expected capital, Pembina plans to make equity contributions to the joint ventures and advances to related parties totaling $160 million, with the remaining capital to be funded within the joint venture entities.

Pembina plans to spend $110 million in 2019 to further advance development of CKPC's integrated propane dehydrogenation (PDH) plant and polypropylene (PP) upgrading facility, including progressing engineering to secure lump sum construction contracts on both the PDH and PP plants.

The company said it is committed to developing this project within its financial guardrails and continues to engage in commercial discussions to secure approximately 50 per cent of its expected cash flows from the PDH/PP Facility on long-term, fixed-return basis.  While progress has been made, Pembina said it has not yet reached the contractual threshold required to make a final investment decision and it continues to work with an objective to achieve the required threshold to make a positive final investment decision by early 2019.

Pembina is currently in the process of commissioning over $750 million of new projects, including the Phase IV and Phase V Peace Pipeline expansions, the Burstall storage facility and the Redwater cogeneration facility, which will come into service in the next several weeks. Based on contributions from these projects and Pembina's expectations and outlook for 2019, the company is anticipating annual adjusted EBITDA of $2.8 to $3 billion.

The Pipelines Division will benefit from increased revenue volumes across the Peace Pipeline system following the completion of the Phase IV and Phase V expansions. Additional contributions are expected from the Alberta Ethane Gathering System based on the re-contracting of approximately 95 per cent of the existing capacity, effective Jan. 1, 2019.

The Facilities division is expected to benefit from a full year of run-rate operations at Veresen Midstream's Dawson facilities as well as the Burstall storage facility and the start-up of Duvernay II.

The outlook for the Marketing & New Ventures Division is based on an expectation of narrower NGL frac spreads driven by lower NGL prices compared to 2018. Pembina has currently hedged approximately 10 per cent of its 2019 frac spread exposure, excluding Aux Sable.

JuneWarren-Nickle's Energy Group

Wells Licensed

A total of 9,226 wells have been licensed across Canada in the January-to-November period, up four per cent from 8,867 permits granted in the comparable period last year, as a rush in oilsands evaluation well licensing helped to boost permitting counts.

There were 1,349 wells authorized in November, up from 1,110 wells authorized in November 2017 and 1,051 wells in November 2016.

There were 819 licences approved in Alberta during November, up 44 per cent from 570 licences issued a year ago. It was the province’s highest monthly count this year for well licences.

Over the first 11 months of 2018, well permitting in Alberta has increased 11 per cent to 5,024 compared to 4,508 wells in January-November 2017.

In Saskatchewan, 328 wells were licensed last month, down from 388 a year ago (down 15 per cent). During January to November of 2018, a total of 3,080 wells have been licensed compared to 3,287 in the year-prior period (down six per cent).

British Columbia approved (input) 171 new licences in November, up from 122 approved a year ago. To the end of November, B.C. has approved 851 new wells, up one per cent from 840 in the January-to-November period last year.

In Manitoba, 31 new wells were licensed last month compared to 27 a year ago, while the 11-month tally has increased by 18 per cent to 256 from 217 a year ago.

Operators licensed 414 oilsands evaluation wells in November, up from 100 permits issued in November 2017, and a monthly high for 2018. Over the first 11 months of the year, 787 oilsands evaluation wells have been licensed compared to 194 last year.

Producers in Western Canada licensed 597 wells to drill for oil or bitumen in November, down from 682 a year ago.

To the end of November, records show 5,776 permits were approved in Western Canada to drill for oil or bitumen, up slightly from 5,728 licences last year.

Gas permitting in the three western-most provinces over the first 11 months of 2018 totalled 1,757 wells, up from 1,551 permits last year.

Across Western Canada, producers licensed 265 gas wells in November compared to 162 a year ago.

This year’s 11-month total includes 7,285 horizontal wells (excluding experimental wells), or about 87 per cent of the total. Last year, to the end of November, operators had permitted 7,352 horizontal wells (again, excluding experimental wells), or about 86 per cent of the total.

Including experimental wells, Suncor Energy Inc. led producers by licensing 245 wells in November.

Second-place finisher Canadian Natural Resources Limited permitted 145 wells, while Encana Corporation licensed 70 wells. Baytex Energy Corp. had 69 licences last month and Crescent Point Energy Corp. permitted 67 wells in November.

At the 11-month mark, including experimental wells, Canadian Natural has licensed 942 wells, followed by Crescent Point (681), Encana (449), Husky Energy Inc. (402) and Baytex (386).

JuneWarren-Nickle's Energy Group