加拿大石油和天然气有增长空间，但未来存在潜在陷阱

监管问题、通货膨胀和外卖能力可能会阻碍项目，而北湾可能会为加拿大陷入困境的离岸行业注入新的活力。

马修·凯勒、恩弗勒斯

尽管魁北克省去年是世界上第一个禁止新的石油和天然气勘探和开发的国家，但它与加拿大一样一开始就没有生产，特别是在加拿大西部沉积盆地（WCSB），未来几年持续增长。然而，新旧障碍可能会给该国的运营商带来挑战。

加拿大陆上产量的大部分来自艾伯塔省、不列颠哥伦比亚省和萨斯喀彻温省。根据加拿大能源监管机构的数据，2020 年这三个省份的石油产量总计约为 4.4 MMbbl/d，天然气产量为 15.5 Bcf/d。这分别占该国石油和天然气总产量的92%和近100%，而当时阿尔伯塔省仍因外运能力有限而实施石油生产限制。

根据 Enverus Intelligence Research (EIR) 最近的报告，预计到 2028 年，阿尔伯塔省和不列颠哥伦比亚省 Montney 区的天然气产量每年将增长约 8.5%，这将使 WCSB 产量从 17 Bcf/d 提高到 20 Bcf/d。阿尔伯塔省的油砂约占加拿大已探明石油储量的 97%，预计在接下来的十年中也将保持其历史增长趋势，到 2030 年将达到 4.2 MMbbl/d，而 2030 年为 3.5 MMbbl/d。 2022 年底。

该国的上游并购活动也保持健康。根据 Enverus 并购分析公司的数据，去年宣布了 83 笔交易（包括特许权使用费交易），其中 62 笔公布的交易价值超过 130 亿美元（174 亿加元）。虽然 2021 年交易活动较多，达到 130 笔，但其中 87 笔交易的已知总价值较低，为 127 亿美元（170 亿加元）。相比之下，2022 年美国的并购活动有所减少，约 150 笔交易交易金额达 580 亿美元（777 亿加元），甚至少于 2020 年宣布的 170 笔交易，且远低于 740 亿美元（992 亿加元）的平均总价值在过去十年中。

尽管如此，运营商仍面临着困难。有些是其他司法管辖区常见的，有些是加拿大特有的。过去一年多来，通胀压力一直是全球现象，能源行业也未能幸免。根据 EIR 和 Enverus 的钻机日费率数据，在美国，去年总体油井成本增加了近 30%，而每次退出时的钻机费率上涨了近 48%。虽然不同的局部因素影响加拿大盆地的价格，但设备利用率高、供应链缓慢和油田服务需求稳定的宏观驱动因素应该会在类似的通胀结果中体现出来。

多年来，外卖能力一直是人们关注的问题。由于石油管道运力不足，艾伯塔省实施了持续近两年的生产限制，直到 2020 年 12 月，新冠肺炎 (COVID-19) 导致产量下降后才结束。Enbridge 的 3 号线替代项目于 2021 年底上线，产能翻倍至 76 万桶/天，而 TC Energy 的 83 万桶/天 Keystone XL 管道项目被终止。跨山管道扩建项目目前预计将于 2023 年底开始管道填充，产能将从 30 万桶/日增至 89 万桶/日。 

重油产量及管道外运能力
WCSB 的历史和预测重油产量以及管道输送能力。（来源：Enverus Intelligence、AER）

EIR表示，这应该会给运营商在未来十年内将原油从WCSB输送出去的机会，但由于没有规划新的管道，生产商可能会被迫限制产量或在2030年代使用更昂贵的铁路运输。WCSB 的天然气外送能力有时也成为一个问题，正如 2022 年下半年 Nova 天然气传输线 (NGTL) 出现瓶颈一样。虽然预计 2023 年盆地内需求的增加和最近 NGTL 的扩张应该会缓解这种情况，但 WCSB 天然气市场的波动可能会持续到 2025 年加拿大液化天然气公司上线。

排放是增长的另一个风险，联邦政府预计将在今年年初颁布 2030 年减排计划。运营商反对一项到 2030 年将行业排放量较 2019 年水平减少 42% 的提案草案。EIR 认为，如果该草案获得通过，在没有广泛采用碳捕获、利用和封存等技术的情况下，这可能会抑制产量增长。缓解投资。 

一些公司和行业团体已经在规划碳封存项目，但可能不足以实现 42% 的目标。去年，阿尔伯塔省从其首次完整提案请求中选择了六个拟议的碳捕获和封存项目，包括 Pembina Pipeline 和 TC Energy 的阿尔伯塔碳网格、Enbridge 的 Wabamun 枢纽、壳牌的 Atlas 枢纽等，这些项目总共可以储存超过建成后每年排放 40 公吨二氧化碳。油砂生产商路径联盟的目标是到 2030 年将二氧化碳排放量减少 22 公吨，该联盟也于 1 月初获得批准，开始对其拟议的 179 亿美元（240 亿加元）碳储存中心进行详细评估。

苦苦挣扎的海上新生活

加拿大的另一个主要生产来源地位于东部纽芬兰和拉布拉多省近海，尽管与 WCSB 相比相形见绌。第一个海上开发项目 Hibernia 于 1997 年开始生产。2005 年至 2017 年间，Terra Nova、Hebron 和 White Rose 及其卫星也加入了该项目。11 月，加拿大纽芬兰和拉布拉多近海和石油委员会发布的统计数据显示，这些油田截至 2022 年 3 月 31 日的 12 个月内，平均日产量接近 25 万桶。根据加拿大能源监管机构的数据，它们也生产天然气，但用于海上设施的发电，重新注入以维持储层压力，有时还进行火炬燃烧。

加拿大近海盆地第四季度活动
加拿大近海盆地第四季度的活动。（来源：Enverus 情报）

近年来，该地区也经历了相当多的挣扎。2019 年末，在项目合作伙伴首次批准延长寿命项目的几个月后，由于出现了一系列安全和监管违规问题，C-NLOPB 命令 Suncor 停止 Terra Nova 的运营。其中一个问题导致去年 12 月 Suncor 因 2019 年 12 月在 FPSO 上受伤而受到指控。延寿项目一度面临取消，但在项目重组后于2021年下半年11时得以挽救。Terra Nova 目前预计将于 2023 年第一季度恢复生产。

West White Rose 项目目前由 Cenovus 收购 Husky Energy 运营，该项目于 2020 年油价暴跌后暂停。去年才恢复工作，预计要到2026年上半年才能交付第一批石油。 

2019 年，埃克森美孚牵头的 Hibernia 项目因漏油事故而停工两个月。在第一次尝试恢复生产后，停工时间延长了，当时停电导致消防雨淋系统释放水，溢出排水罐，并向海洋释放更多石油。

目前规划的唯一重大新项目是 Equinor 的 Bay du Nord 枢纽。这家挪威运营商暂停了 2020 年的规划工作，但当年晚些时候在卡帕海登和坎布里奥尔有了新发现，目前正在开发一个更大的项目。加拿大监管机构去年批准了一项环境评估，但几个环保组织提起诉讼，寻求停止该项目。据报道，1 月下旬，该公司向潜在海上承包商发出通知，要求他们提交对该项目计划的 20 万桶/天 FPSO 的意向书。 

去年年底，Equinor 和合作伙伴 BP 还在 C-NLOPB 的 2022 年竞标中获得了 Bay du Nord 附近的三个许可证。尽管监管机构提供了 28 个不同的地块，覆盖面积超过 700 万公顷，最低工程承诺为 750 万美元（1000 万加元），但最终只有 5 个投标成功。埃克森美孚表现出色，以 1.355 亿美元（1.816 亿加元）的价格竞购了占地 267,686 公顷的第 8 号地块。其余四个成功竞标的工程承诺金额从 810 万美元到 1,230 万美元（1,080 万加元到 1,650 万加元）不等。

原文链接/hartenergy

Oil and Gas Have Room to Grow in Canada, But Potential Pitfalls Ahead

Regulatory issues, inflation and takeaway capacity could hold up projects, while Bay du Nord could breathe new life into Canada’s struggling offshore sector.

Matthew Keillor, Enverus

While Quebec was the world’s first to ban new oil and gas exploration and development last year—although it had no production to begin with—Canada’s production, particularly in the Western Canada Sedimentary Basin (WCSB), is poised for continued growth in the coming years. However, old and new roadblocks could pose challenges for operators in the country.

The lion’s share of Canada’s onshore output comes from Alberta, British Columbia and Saskatchewan. Together these three provinces produced almost 4.4 MMbbl/d of oil and 15.5 Bcf/d of natural gas in 2020, according to the Canada Energy Regulator. This accounted for 92% and nearly 100% of the country’s total oil and gas production, respectively, and at a time when Alberta was still imposing oil production restrictions as a result of limited takeaway capacity.

According to recent reports from Enverus Intelligence Research (EIR), gas production in Alberta and B.C.’s Montney play is forecast to grow by about 8.5% annually through 2028, which will lift WCSB output from 17 Bcf/d to 20 Bcf/d. Alberta’s oil sands, which represent about 97% of Canada’s proven oil reserves, are also expected to maintain their historical growth trend through the rest of the decade, reaching 4.2 MMbbl/d by 2030 compared to 3.5 MMbbl/d at the end of 2022.

Upstream M&A activity has also remained healthy in the country. According to Enverus M&A Analytics, there were 83 deals—including royalty transactions—announced last year, including 62 with announced values exceeding $13 billion (C$17.4 billion). While 2021 had more activity at 130 deals, the known aggregate value was lower at $12.7 billion (C$17 billion) from 87 of the deals. Comparatively, M&A activity in the U.S. had a down year in 2022, with $58 billion (C$77.7 billion) from about 150 deals, even fewer than the 170 announced in 2020 and well below the average aggregate value of $74 billion (C$99.2 billion) over the last decade.

Still, difficulties lie ahead for operators to navigate. Some are common with other jurisdictions and some are specific to Canada. Inflationary pressure has been a global phenomenon for the past year or more, and the energy industry has not been immune. In the U.S., overall well costs increased nearly 30% last year, and rig rates rose nearly 48% exit-to-exit, according to EIR and Enverus’ rig day rate data. While different localized factors impact prices in Canadian basins, the macro drivers of high equipment utilization rates, slow supply chains and steady demand for oilfield services should manifest in similar inflation results.

Takeaway capacity has been a concern for several years. A dearth of oil pipeline capacity led Alberta to impose production restrictions that lasted nearly two years, ending only in December 2020 after COVID-19 tanked output. Enbridge’s Line 3 replacement came online in late 2021, doubling its capacity to 760,000 bbl/d, while TC Energy’s 830,000 bbl/d Keystone XL pipeline project was killed. The Trans Mountain pipeline expansion project, now expected to begin linefill by the end of 2023, will increase capacity to 890,000 bbl/d from 300,000 bbl/d. 

heavy oil production and pipeline takeaway capacit
Historical and forecast heavy oil production and pipeline takeaway capacity in the WCSB. (Source: Enverus Intelligence, AER)

That should give operators some runway through the rest of the decade to get their crude out of the WCSB, but with no new pipelines planned, producers could be forced to limit output or use more expensive rail transport into the 2030s, according to EIR. Gas takeaway capacity in the WCSB has also been an issue at times, as seen in the second half of 2022 with bottlenecks on the Nova Gas Transmission Line (NGTL). While that should be alleviated with additional in-basin demand expected in 2023 and recent NGTL expansions, volatility in the WCSB gas market will likely continue until LNG Canada goes online in 2025.

Emissions are another risk to growth, with the federal government expected to enact a 2030 Emission Reduction Plan early this year. Operators have opposed a draft proposal to reduce sector emissions 42% from 2019 levels by 2030. If such a draft is adopted, the EIR believes it will likely dampen production growth in the absence of wide scale adoption of carbon capture, utilization and sequestration and other mitigation investments. 

Several companies and industry groups are already planning carbon sequestration projects, but they may not be enough to meet the 42% target. Alberta selected six proposed carbon capture and sequestration projects last year from its first request for full proposals, including Pembina Pipeline and TC Energy’s Alberta Carbon Grid, Enbridge’s Wabamun hub, Shell’s Atlas hub and others, which together could store over 40 mtpa of CO2 once built. The Pathways Alliance of oil sands producers—which aims to reduce their CO2 emissions by 22 mtpa by 2030—also received approval to begin a detailed evaluation of its proposed $17.9 billion (C$24 billion) carbon storage hub in early January.

New life for struggling offshore

Canada’s other major source of production, although it pales in comparison to the WCSB, is offshore the eastern province of Newfoundland and Labrador. The first offshore development, Hibernia, began production in 1997. It was joined by Terra Nova, Hebron and White Rose and its satellites between 2005 and 2017. In November, the Canada-Newfoundland and Labrador Offshore and Petroleum Board released statistics showing that the fields averaged nearly 250,000 bbl/d during the 12 months ended March 31, 2022. They produce gas as well, but it is used for power on offshore facilities, reinjected to maintain reservoir pressure or sometimes flared, according to the Canada Energy Regulator.

Q4 activity in Canada's offshore basins
Q4 activity in Canada's offshore basins. (Source: Enverus Intelligence)

The region has had its fair share of struggles in recent years. The C-NLOPB ordered Suncor to halt operations at Terra Nova in late 2019—months after the project partners had first sanctioned a life extension project—following a series of safety and regulatory noncompliance issues. One of those issues resulted in charges being laid against Suncor last December for a December 2019 injury onboard the FPSO. The life extension project faced cancellation but was saved at the 11th hour in the second half of 2021 following a restructuring of the project. Terra Nova is now expected to resume production in the first quarter of 2023.

The West White Rose project, now operated by Cenovus following its acquisition of Husky Energy, was suspended in 2020 following the oil price crash. Work only resumed last year, and it is not expected to deliver first oil until the first half of 2026. 

The ExxonMobil-led Hibernia project suffered a two-month shutdown in 2019 following an oil spill. That stoppage was extended after the first attempt to resume production, when a power loss caused the firefighting deluge system to release water, overflowing drain tanks and releasing more oil into the ocean.

The only major new project currently planned is Equinor’s Bay du Nord hub. The Norwegian operator temporarily suspended planning work in 2020, but it made new discoveries at Cappahayden and Cambriol later that year and is now working on developing a larger project. Canadian regulators approved an environmental assessment last year, but several environmental groups filed a lawsuit seeking to halt the project. In late January, the company reportedly issued a notice to potential offshore contractors to submit an expression of interest in relation to the project’s planned 200,000 bbl/d FPSO. 

Equinor and partner BP also picked up three licenses adjacent to Bay du Nord late last year in C-NLOPB’s 2022 bid round. Although the regulator offered 28 different parcels covering over 7 million hectares with a minimum work commitment of $7.5 million (C$10 million), only five bids were ultimately successful. ExxonMobil was the standout, bidding $135.5 million (C$181.6 million) for the 267,686-hectare Parcel 8. The remaining four successful bids had work commitments ranging from $8.1 million to $12.3 million (C$10.8 million to C$16.5 million).