CALGARY, AB – Pembina Pipeline Corporation (“Pembina” or the “Company”) (TSX: PPL)(NYSE: PBA) announced today its financial and operating results for the third quarter of 2021.
Highlights
- Third quarter earnings of $588 million and adjusted EBITDA of $850 million reflect strong pricing across all commodities in Pembina’s value chain.
- During the quarter, Pembina received payment of a $350 million (pre-tax) fee related to the termination of the proposed acquisition of Inter Pipeline.
- Pembina recently announced its target to reduce greenhouse gas emissions intensity by 30 percent by 2030, relative to baseline 2019 emissions.
Financial and Operational Overview
3 Months Ended September 30 |
9 Months Ended September 30 |
|||
($ millions, except where noted)(unaudited) |
2021 |
2020(3) |
2021 |
2020(3) |
Infrastructure and other services revenue |
756 |
744 |
2,240 |
2,199 |
Product sales revenue |
1,393 |
752 |
3,827 |
2,074 |
Total revenue |
2,149 |
1,496 |
6,067 |
4,273 |
Net revenue(1) |
961 |
849 |
2,854 |
2,490 |
Earnings |
588 |
323 |
1,162 |
900 |
Earnings per common share – basic & diluted (dollars) |
1.01 |
0.52 |
1.92 |
1.42 |
Cash flow from operating activities |
913 |
434 |
1,953 |
1,486 |
Cash flow from operating activities per common share – basic (dollars)(1) |
1.66 |
0.78 |
3.55 |
2.70 |
Adjusted cash flow from operating activities(1) |
786 |
524 |
1,906 |
1,686 |
Adjusted cash flow from operating activities per common share – basic (dollars)(1) |
1.43 |
0.95 |
3.47 |
3.07 |
Common share dividends declared |
347 |
346 |
1,040 |
1,039 |
Dividends per common share (dollars) |
0.63 |
0.63 |
1.89 |
1.89 |
Capital expenditures |
209 |
174 |
482 |
868 |
Total volume (mboe/d)(2) |
3,411 |
3,451 |
3,464 |
3,462 |
Adjusted EBITDA(1) |
850 |
796 |
2,463 |
2,415 |
(1) |
Refer to “Non-GAAP Measures”. |
(2) |
Total revenue volumes. Revenue volumes are physical volumes plus volumes recognized from take-or-pay commitments. Volumes are stated in thousand barrels of oil equivalent per day (“mboe/d”), with natural gas volumes converted to mboe/d from millions of cubic feet per day (“MMcf/d”) at a 6:1 ratio. |
(3) |
Comparative 2020 period has been restated. See “Voluntary Change in Accounting Policy” and “Restatement of Revenue and Cost of Goods Sold” in Pembina’s management’s discussion and analysis for the three and nine months ended September 30, 2021 (“MD&A”) and Note 2 to Pembina’s unaudited condensed consolidated interim financial statements as at and for the three and nine months ended September 30, 2021 (“Interim Financial Statements”). |
Financial and Operational Overview by Division
3 Months Ended September 30 |
9 Months Ended September 30 |
|||||||||||
2021 |
2020 |
2021 |
2020 |
|||||||||
($ millions, except where noted) |
Volumes(1) |
Gross Profit |
Adjusted EBITDA(2) |
Volumes(1) |
Gross Profit(4) |
Adjusted EBITDA(2) |
Volumes(1) |
Gross Profit |
Adjusted EBITDA(2) |
Volumes(1) |
Gross Profit(4) |
Adjusted |
Pipelines |
2,563 |
347 |
503 |
2,580 |
381 |
541 |
2,592 |
1,047 |
1,554 |
2,588 |
1,159 |
1,631 |
Facilities |
848 |
233 |
273 |
871 |
182 |
251 |
872 |
628 |
812 |
874 |
523 |
757 |
Marketing & New Ventures Ventures(3) |
— |
100 |
109 |
— |
5 |
34 |
— |
185 |
237 |
— |
77 |
118 |
Corporate |
— |
2 |
(35) |
— |
— |
(30) |
— |
2 |
(140) |
— |
2 |
(91) |
Total |
3,411 |
682 |
850 |
3,451 |
568 |
796 |
3,464 |
1,862 |
2,463 |
3,462 |
1,761 |
2,415 |
(1) |
Volumes for Pipelines and Facilities divisions are revenue volumes, which are physical volumes plus volumes recognized from take-or-pay commitments. Volumes are stated in mboe/d, with natural gas volumes converted to mboe/d from MMcf/d at a 6:1 ratio. |
(2) |
Refer to “Non-GAAP Measures”. |
(3) |
Marketed natural gas liquids (“NGL”) volumes are excluded from Volumes to avoid double counting. Refer to “Marketing & New Ventures Division” in Pembina’s MD&A for further information. |
(4) |
Comparative 2020 period has been restated. See “Voluntary Change in Accounting Policy” in Pembina’s MD&A and Note 2 to Pembina’s Interim Financial Statements. |
Financial & Operational Highlights
Adjusted EBITDA
Change in Third Quarter Adjusted EBITDA ($ millions)(1)(2)
(1) |
Comparative 2020 period has been restated. See “Voluntary Change in Accounting Policy” in Pembina’s MD&A and Note 2 to Pembina’s Interim Financial Statements. |
(2) |
Refer to “Non-GAAP Measures”. |
Pembina reported strong adjusted EBITDA of $850 million for the third quarter, seven percent higher than the same period in the prior year. Higher margins on NGL and crude oil sales and the positive impact of higher marketed NGL volumes were partially offset by a realized loss on commodity-related derivatives compared to a realized gain in the prior period. In addition, the year-over-year increase was due to contributions from assets placed into service in Facilities including Prince Rupert Terminal, Empress Infrastructure, Duvernay III and Hythe Developments, as well as higher volumes at Veresen Midstream’s Dawson Assets and higher volumes on the Peace Pipeline system. These positive factors were partially offset by the impact of a lower U.S. dollar exchange rate, a lower contribution from Ruby Pipeline due to lower contracted volumes, lower revenue from Cochin Pipeline due to the impact of a timing difference in the recognition of deferred revenue, and higher general and administrative expense due to higher long-term incentive expenses as a result of changes in Pembina’s share price.
Earnings
Change in Third Quarter Earnings ($ millions)(1)(2)(3)
(1) |
Comparative 2020 period has been restated. See “Voluntary Change in Accounting Policy” in Pembina’s MD&A and Note 2 to Pembina’s Interim Financial Statements. |
(2) |
Facilities results ex. commodity-related derivatives and Marketing & New Ventures results ex. commodity-related derivatives include gross profit less realized and unrealized losses on commodity-related derivative financial instruments. |
(3) |
Other includes other expenses, impairments and corporate. |
Pembina reported earnings of $588 million for the third quarter, 82 percent higher than the same period in the prior year. In addition to the factors impacting adjusted EBITDA, as noted above, earnings were positively impacted by the receipt of the $350 million payment associated with Pembina’s termination of its proposed acquisition of Inter Pipeline, net of the related tax impact, a higher unrealized gain related to certain gas processing fees tied to AECO natural gas prices, and an unrealized gain on commodity-related derivatives compared to a loss in the prior period. These positive factors were offset by higher net finance costs due to a foreign exchange loss, compared to a gain in the prior period, and lower share of profit from Ruby Pipeline.
Cash Flow From Operating Activities
Cash flow from operating activities of $913 million for the third quarter was an increase of 110 percent over the same period in the prior year. The increase was driven primarily by receipt of the payment associated with Pembina’s termination of the proposed acquisition of Inter Pipeline; an increase in operating results, as discussed above, after adjusting for non-cash items; a change in non-cash working capital; and a decrease in taxes paid. These positive factors were partially offset by an increase in net interest paid. On a per share (basic) basis, cash flow from operating activities for the third quarter increased due to the same factors.
Adjusted Cash Flow From Operating Activities
Adjusted cash flow from operating activities of $786 million was 50 percent higher compared to the same period in the prior year. The increase is due to the same factors impacting cash flow from operating activities, discussed above, net of the change in non-cash working capital and decrease in taxes paid, partially offset by higher current tax expense and an increase in accrued share-based payments. On a per share (basic) basis, adjusted cash flow from operating activities for the third quarter increased due to the same factors.
Volumes
Total volumes of 3,411 mboe/d for the third quarter represent an approximately one percent decrease over the same period in the prior year.
Divisional Highlights
- Pipelines reported adjusted EBITDA for the third quarter of $503 million, representing a seven percent decrease compared to the same period in the prior year. The decrease was largely due to a lower contribution from Ruby Pipeline due to lower contracted volumes, lower revenue from Cochin Pipeline due to the impact of a timing difference in the recognition of deferred revenue, and the impact of a lower U.S. dollar exchange rate. These factors were partially offset by higher volumes on Peace Pipeline.
Pipelines volumes of 2,563 mboe/d in the third quarter represent a one percent decrease compared to the same period in the prior year. The decrease was driven by lower contracted volumes on Ruby Pipeline due to contract expirations, lower interruptible volumes on AEGS due to third party outages, and lower volumes on Vantage Pipeline. These decreases were partially offset by higher volumes on Peace Pipeline and Alliance Pipeline.
- Facilities reported adjusted EBITDA of $273 million for the third quarter, which represents a nine percent increase over the same period in the prior year. The increase was primarily due to the contribution from Empress Infrastructure and Duvernay III, which were placed into service in the fourth quarter of 2020, and Prince Rupert Terminal and Veresen Midstream’s Hythe Developments, which were placed into service in March 2021, as well as higher volumes at Younger due to a turnaround in the prior year.
Facilities volumes of 848 mboe/d in the third quarter were three percent lower than the same period in the prior year. The decrease was largely due to take-or-pay relief provided to Redwater Complex customers following third-party outages during the quarter, lower volumes at Saturn Complex due to higher deferred revenue volumes recognized in the same period in the prior year, and lower supply volumes on the East NGL System as volumes are now being processed at Empress NGL Extraction Facility. These factors were partially offset by higher volumes at Younger due to a turnaround in the prior year, higher volumes at Veresen Midstream’s Dawson Assets and higher volumes associated with Duvernay III being placed into service in the fourth quarter of 2020.
- Marketing & New Ventures reported third quarter adjusted EBITDA of $109 million, an increase of $75 million, or 221 percent, over the same period in the prior year. Higher margins were realized on NGL and crude oil sales as a result of higher NGL and crude oil prices and higher marketed NGL volumes. This was partially offset by a realized loss on commodity-related derivatives, due to higher NGL and crude oil market prices, compared to a realized gain in the same period in the prior year. Excluding the impact of realized losses on commodity-related derivatives, third quarter adjusted EBITDA increased $127 million over the same period in the prior year.
Marketed NGL volumes of 177 mboe/d in the third quarter represent a five percent increase compared to the same period in the prior year. Marketed NGL volumes increased as sales have returned to pre-pandemic levels compared to the third quarter of 2020 when Pembina built up storage positions due to lower commodity prices.
Executive Overview
We are very pleased to report strong third quarter results reflecting continued robust pricing across all commodities in Pembina’s value chain – crude, condensate, natural gas and NGL. The current commodity price environment is supportive of our outlook for 2021 and 2022, as well as the longer-term prospects for Pembina’s business, including a robust backlog of currently deferred and potential new growth projects totaling more than $5 billion.
As the Company continues to advance its ESG strategy, we were pleased recently to announce our target to reduce Pembina’s greenhouse gas (“GHG”) emissions intensity by 30 percent by 2030, relative to baseline 2019 emissions. The GHG reduction target will help guide business decisions and improve overall emissions intensity performance while increasing Pembina’s long-term value and ensuring Canadian energy is developed and delivered responsibly. To meet the target, Pembina will focus initially on operational opportunities, greater use of renewable and lower emission energy sources, and investments in a lower carbon economy. In addition to the GHG target, Pembina expects to make further ESG progress with the announcement of Equity, Inclusion and Diversity targets by the end of 2021.
Looking ahead, a number of fundamental developments within our business and across the broader industry make us increasingly optimistic about the prospects for Pembina and, by extension, each of our stakeholders:
- Underinvestment and capital discipline among producers is driving natural gas and NGL prices to a seven year high and inventories remain at below average levels as we head into winter. These conditions support our view of strong pricing continuing into 2022, creating an opportunity for Pembina to maintain an above average contribution from our marketing business. As disclosed previously, the Company has hedged approximately 50 percent of its 2021 frac spread exposure, excluding Aux Sable. For 2022, the Company has now hedged approximately 38 percent of its frac spread exposure, excluding Aux Sable.
- Our producer customers’ financial health is as strong as it has ever been. Despite the broader inflationary pressures in the global economy, ingenuity and continuous improvement have driven efficiencies, enabling producers to deliver more value with the same development dollars. While we expect continued financial discipline by producers, we also recognize that increasing energy prices may eventually necessitate a supply response to meet the world’s near-term energy needs. This would clearly have positive implications for Pembina.
- We were encouraged to see a recent significant announcement from DOW Chemical Co., highlighting plans to build a new polyethylene cracker in Fort Saskatchewan, Alberta. The announced project would represent a significant increase in ethane demand in Alberta as we estimate over 100,000 barrels per day of new ethane feedstock supply could be required. This should have positive implications for third-party service providers, as new infrastructure will be required for ethane extraction and transportation.
- Alliance Pipeline has tremendous utility and over the long term offers reliable and highly competitive access to the mid-western U.S. gas markets, as well as a conduit to the Gulf Coast and the robust liquefied natural gas (“LNG”) market. A recent open season for short-term capacity was nearly three times over-subscribed, resulting in Alliance being essentially fully contracted for 2022. The current outlook also supports contracting of capacity beyond 2022 and we look forward to providing further updates by the end of the year.
- The completion of the Line 3 Replacement Project represents a major milestone for the industry and meaningfully advances Western Canadian oil egress. In conjunction with the Trans Mountain Pipeline expansion currently under construction, we expect the Western Canadian Sedimentary Basin will soon have up to 750,000 barrels per day of excess takeaway capacity, providing ample opportunity for supply to grow meaningfully to fill the gap, with the potential for related benefits to accrue to Pembina over the long-term.
With strong pricing providing a steady tailwind for our business, we remain optimistic about the future. We will continue to advance our ESG strategy and progress development of future growth opportunities. Finally, we remain on track to deliver full year 2021 adjusted EBITDA within our guidance range of $3.3 – $3.4 billion and look forward to providing our outlook for 2022 with the release of our guidance and capital budget update in early December.
Projects and New Developments (1)
Pipelines:
- Pembina continues to progress its Phase VII Peace Pipeline Expansion (“Phase VII”), which includes a new 20-inch, approximately 220 km pipeline and two new pump stations or terminal upgrades. Phase VII will add approximately 160,000 barrels per day of incremental capacity upstream of Fox Creek, accessing capacity available on the mainlines downstream of Fox Creek. Construction is underway and the project is trending under its $775 million budget and ahead of schedule relative to the expected in-service date in the first half of 2023.
- The Phase IX Peace Pipeline Expansion (“Phase IX”) will add capacity in the northwest Alberta-to-Gordondale, Alberta corridor to accommodate increased activity in the northeast British Columbia Montney play. Phase IX also includes a pump station in the Wapiti-to-Kakwa corridor that was previously part of the Phase VII project scope. The project has an estimated cost of approximately $120 million and an expected in-service date in the second half of 2022.
- The previously announced Phase VIII Peace Pipeline Expansion (“Phase VIII”) remains deferred. Initial contracts supporting the project remain intact and customers continue to signal plans which will necessitate the incremental capacity. Value engineering work is ongoing and Pembina continues to evaluate this project in discussions with its producing customers with a reactivation decision expected in the fourth quarter of 2021. Prior to deferral, Phase VIII had an associated capital cost of approximately $500 million but Pembina expects this level of investment to decrease given cost and scope improvements.
Facilities:
- Pembina continues to progress the Empress Cogeneration Facility. The facility will use natural gas to generate up to 45 megawatts of electrical power, reducing overall operating costs by providing power and heat to the existing Empress NGL Extraction Facility. All the power will be consumed on site, supplying approximately 90 percent of the site’s power requirements. Further, this project will contribute to annual greenhouse gas emission reductions at the Empress NGL Extraction Facility through the utilization of cogeneration waste heat and low-emission power generated. Pembina anticipates a reduction of approximately 90,000 tonnes of carbon dioxide equivalent per year based on the current energy demand of the Empress NGL Extraction Facility. Construction is progressing and the mechanical contractor is expected to mobilize to site in November 2021. The project has an expected in-service date in the fourth quarter of 2022.
- The Prince Rupert Terminal Expansion remains deferred. Engineering of the expansion is well advanced and Pembina expects to make a final investment decision in the first quarter of 2022.
__________________________ |
|
(1) |
For further details on the Company’s significant assets, including definitions for capitalized terms used herein that are not otherwise defined, refer to Pembina’s Annual Information Form for the year ended December 31, 2020 filed at www.sedar.com (filed with the U.S. Securities and Exchange Commission at www.sec.gov under Form 40 F) and on Pembina’s website at www.pembina.com. |
Marketing & New Ventures:
- Pembina’s New Ventures continues to advance business opportunities in petrochemicals, terminals, including LNG, and low-carbon energy. New Ventures is focused on developing opportunities that integrate into Pembina’s core businesses, while progressing projects that will extend Pembina’s value-chain and benefit stakeholders. Pembina has formed a strategic partnership agreement with the Haisla First Nation to develop the proposed Cedar LNG Project, a floating LNG facility strategically positioned to leverage Canada’s abundant natural gas supply and British Columbia’s growing LNG infrastructure to produce industry-leading low–carbon, low-cost Canadian LNG for overseas markets. The Cedar LNG Project is expected to be the largest First Nation-owned infrastructure project in Canada and have one of the cleanest environmental profiles in the world. In addition, Pembina and TC Energy Corporation intend to jointly develop the Alberta Carbon Grid, a world-scale carbon transportation and sequestration system, which will enable Alberta-based industries to effectively manage their greenhouse gas emissions, contribute positively to Alberta’s lower-carbon economy and create sustainable long-term value for Pembina and TC Energy stakeholders.
Restatement of Revenue and Cost of Goods Sold in 2020 Financial Statements
During the third quarter, management identified certain crude contracts within Pembina’s Marketing and New Ventures Division that were recorded incorrectly as it relates to gross versus net revenue. There is no impact to Pembina’s balance sheet or any of the following: net revenue, gross profit, earnings, cash flow from operating activities, adjusted cash flow from operating activities or adjusted EBITDA. As a result, Pembina intends to refile its consolidated financial statements for the year ended December 31, 2020 and the management discussion and analysis with respect thereto to reflect the restated revenue and cost of goods sold figures for the years ended December 31, 2020 and 2019. The estimated adjustments are as follows:
($ millions, unaudited) |
2021 |
2020 |
2019 |
|||||||
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
|
Revenue previously reported |
1,954 |
2,045 |
1,694 |
1,569 |
1,268 |
1,671 |
1,754 |
1,700 |
1,808 |
1,968 |
Restatement adjustment |
(52) |
(29) |
(14) |
(73) |
(39) |
(123) |
(86) |
(208) |
(245) |
(319) |
Revenue restated(1) |
1,902 |
2,016 |
1,680 |
1,496 |
1,229 |
1,548 |
1,668 |
1,492 |
1,563 |
1,649 |
Cost of goods sold previously reported |
1,060 |
1,046 |
740 |
720 |
492 |
806 |
917 |
949 |
1,050 |
1,194 |
Restatement adjustment |
(52) |
(29) |
(14) |
(73) |
(39) |
(123) |
(86) |
(208) |
(245) |
(319) |
Cost of good sold restated |
1,008 |
1,017 |
726 |
647 |
453 |
683 |
831 |
741 |
805 |
875 |
Net revenue impact(1)(2) |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
Gross profit and earnings impact(1) |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
(1) |
Revenue for 2018 in the “Selected Annual Information” table in section 9 of the refiled 2020 management’s discussion and analysis will be restated to $6,125 million (from originally reported of $7,351 million). While not disclosed in the 2020 management discussion and analysis, a corresponding restatement of cost of goods sold in 2018 would also be made in connection with this restatement. The adjustments have no impact to Pembina’s balance sheet or any of the following: net revenue, gross profit, earnings, cash flow from operating activities, adjusted cash flow from operating activities or adjusted EBITDA. |
(2) |
Refer to “Non-GAAP Measures”. |
Dividends
- Pembina declared and paid dividends of $0.21 per common share in July, August and September 2021 for the applicable record dates.
- Pembina declared and paid quarterly dividends per Class A Preferred Share of: Series 1: $0.306625; Series 3: $0.279875; Series 5: $0.285813; Series 7: $0.27375; Series 9: $0.268875; and Series 21: $0.30625 to shareholders of record as of August 3, 2021. Pembina also declared and paid quarterly dividends per Class A Preferred Share of: Series 15: $0.279; Series 17: $0.301313; and Series 19: $0.29275 to shareholders of record on September 15, 2021. Pembina also declared and paid quarterly dividends per Class A Preferred Share of Series 23: $0.328125; and Series 25: $0.3250 to shareholders of record on August 3, 2021.
Third Quarter 2021 Conference Call & Webcast
Pembina will host a conference call on Friday, November 5, 2021 at 8:00 a.m. MT (10:00 a.m. ET) for interested investors, analysts, brokers and media representatives to discuss results for the third quarter of 2021. The conference call dial-in numbers for Canada and the U.S. are 647-792-1240 or 800-437-2398. A recording of the conference call will be available for replay until November 12, 2021 at 11:59 p.m. ET. To access the replay, please dial either 647-436-0148 or 888-203-1112 and enter the password 9073529.
A live webcast of the conference call can be accessed on Pembina’s website at www.pembina.com under Investor Centre/ Presentation & Events, or by entering:
https://produceredition.webcasts.com/starthere.jsp?ei=1354435&tp_key=4504814289 in your web browser. Shortly after the call, an audio archive will be posted on the website for a minimum of 90 days.