Vermilion Energy Inc. press release
Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2021
TSX - Toronto Stock Exchange · Canada
Canada NewsWire
CALGARY, AB , Nov. 9, 2021 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET) (NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2021.
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The unaudited interim financial statements and management discussion and analysis for the three and nine months ended September 30, 2021 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com , on EDGAR at www.sec.gov/edgar.shtml , and on Vermilion's website at www.vermilionenergy.com .
Highlights
Fund flows from operations ("FFO") was $263 million in Q3 2021, an increase of 52% from the prior quarter. The increase was primarily due to higher commodity prices.
E&D capital expenditures were $66 million in the quarter, resulting in $196 million of free cash flow ("FCF") (1) and a payout ratio of 27% including reclamation and abandonment expenditures.
Through the first nine months of 2021 we have generated $369 million of FCF and have reduced net debt by $231 million while also funding acquisitions to benefit future FCF deliverability. Based on the forward commodity strip, we expect to generate in excess of $500 million , or over $3.00 per share, of FCF in 2021 and exit the year with net debt forecast to be in the range of $1.65 billion , implying a net debt to trailing FFO ratio of approximately 1.8 times.
Production in Q3 2021 averaged 84,633 boe/d (2) , which was down slightly from the previous quarter primarily due to planned maintenance activity in Canada and Ireland , partially offset by higher production in the Netherlands , Germany , Australia and the United States , including the contribution from a small bolt-on acquisition in the Powder River Basin.
Production from our North American assets averaged 57,022 boe/d in Q3 2021, a decrease of 2% from the prior quarter primarily due to planned and unplanned downtime in Canada , which was partially offset by strong performance from our United States business unit, including the acquisition noted above.
In Canada , we continued with our two-rig drilling program in south-east Saskatchewan where we drilled 19 (19.0 net) wells and completed 20 (19.5 net) wells in the quarter. Activity in Alberta was primarily focused on plant turnarounds and maintenance and preparing for our Q4 2021 condensate-rich Mannville gas drilling program.
In the United States , we completed and brought on production the remaining two (2.0 net) wells from our four (4.0 net) well Q2 2021 drilling program. With our growing knowledge of the Turner play, we were able to identify and execute a strategic acquisition during Q3 2021. The acquisition includes 20,000 net acres of land adjacent to our Hilight field in Wyoming with current production of approximately 1,500 boe/d (72% liquids). We have identified up to 40 drilling locations in the Turner sands along with longer-term resource potential from the emerging Niobrara and Parkman formations. Total consideration for the acquisition was US$76 million which was funded through our credit facility.
Production from our International assets averaged 27,612 boe/d in Q3 2021, a decrease of 1% from the prior quarter primarily due to a planned turnaround in Ireland , which was partially offset by strong performance from the Netherlands , Germany and Australia .
In the Netherlands , the Nijega well (1.0 net) was tied in during the third quarter, while the Blesdijke well (0.5 net) is currently undergoing stimulation operations and is expected to be tested in Q4 2021.
In Germany , the Burgmoor Z-5 well (46% working interest) was brought on production during the third quarter.
Our board of directors have approved a $75 million increase to our 2021 capital program to $375 million . The incremental capital investment will be primarily directed towards our Alberta condensate-rich natural gas drilling, Saskatchewan light oil drilling and seismic acquisitions in Europe . As a result of the strong production achieved year-to-date, combined with the US acquisition completed in Q3 2021, we have increased our 2021 annual production guidance to 84,500 - 85,500 boe/d.
Based on our preliminary work to date, we anticipate a 2022 capital program in the range of $400 - $450 million with production at a similar level to our original 2021 guidance of 83,000 to 85,000 boe/d. Based on this targeted capital and production range and using forward strip pricing for 2022, we anticipate FCF in excess of $600 million with net debt in the range of $1 billion by the end of the year, implying a net debt to trailing FFO ratio of less than 1.0 times.
We plan to reinstate a dividend in Q1 2022. Although it is still subject to board approval, our intention is to reinstate a fixed quarterly dividend (5-10% of FFO stress-tested at lower prices including US$55 /bbl WTI) while continuing to focus on debt reduction. As further debt targets are achieved we will consider augmenting our return of capital through fixed dividend increases, share buybacks and/or special dividends. We will provide more details on our return of capital framework with our formal 2022 budget release in early December.
| (1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. | | (2) | Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion and Analysis for disclosure by product type. |
| ($M except as indicated) | Q3 2021 | Q2 2021 | Q3 2020 | YTD 2021 | YTD 2020 | | | | | | | Financial | | | | | | | | | | | | Petroleum and natural gas sales | 538,530 | | 407,179 | | 282,020 | | 1,313,846 | | 803,347 | | | Fund flows from operations | 262,696 | | 172,942 | | 114,776 | | 597,689 | | 366,853 | | | Fund flows from operations ($/basic share) (1) | 1.62 | | 1.07 | | 0.73 | | 3.72 | | 2.33 | | | Fund flows from operations ($/diluted share) (1) | 1.59 | | 1.05 | | 0.73 | | 3.65 | | 2.33 | | | Net (loss) earnings | (147,130) | | 451,274 | | (69,926) | | 804,108 | | (1,459,720) | | | Net (loss) earnings ($/basic share) | (0.91) | | 2.79 | | (0.44) | | 5.00 | | (9.26) | | | Capital expenditures | 66,450 | | 79,176 | | 31,330 | | 228,989 | | 307,308 | | | Acquisitions | 94,420 | | 12,519 | | 6,720 | | 107,332 | | 20,989 | | | Asset retirement obligations settled | 5,142 | | 3,321 | | 2,305 | | 15,486 | | 7,007 | | | Cash dividends ($/share) | — | | — | | — | | — | | 0.575 | | | Dividends declared | — | | — | | — | | — | | 90,067 | | | % of fund flows from operations | — | % | — | % | — | % | — | % | 25 | % | | Payout (1) | 71,592 | | 82,497 | | 33,635 | | 244,475 | | 396,105 | | | % of fund flows from operations | 27 | % | 48 | % | 29 | % | 41 | % | 108 | % | | Free Cash Flow (1) | 196,246 | | 93,766 | | 83,446 | | 368,700 | | 59,545 | | | Net debt (2) | 1,778,052 | | 1,854,195 | | 2,083,317 | | 1,778,052 | | 2,083,317 | | | Net debt to four quarter trailing fund flows from operations | 2.43 | | 3.17 | | 3.58 | | 2.43 | | 3.58 | | | Operational | | | | | | | | | | | | Production (3) | | | | | | | | | | | | Crude oil and condensate (bbls/d) | 38,777 | | 38,354 | | 43,240 | | 38,777 | | 44,383 | | | NGLs (bbls/d) | 8,068 | | 8,695 | | 9,509 | | 8,279 | | 9,041 | | | Natural gas (mmcf/d) | 226.73 | | 235.72 | | 256.34 | | 232.12 | | 265.39 | | | Total (boe/d) | 84,633 | | 86,335 | | 95,471 | | 85,742 | | 97,656 | | | Average realized prices | | | | | | | | | | | | Crude oil and condensate ($/bbl) | 87.05 | | 79.06 | | 52.77 | | 79.40 | | 49.03 | | | NGLs ($/bbl) | 35.55 | | 25.43 | | 15.04 | | 30.03 | | 11.09 | | | Natural gas ($/mcf) | 9.20 | | 5.24 | | 2.34 | | 6.63 | | 2.37 | | | Production mix (% of production) | | | | | | | | | | | | % priced with reference to WTI | 39 | % | 38 | % | 40 | % | 38 | % | 40 | % | | % priced with reference to Dated Brent | 18 | % | 17 | % | 17 | % | 18 | % | 16 | % | | % priced with reference to AECO | 28 | % | 30 | % | 28 | % | 29 | % | 28 | % | | % priced with reference to TTF and NBP | 15 | % | 15 | % | 15 | % | 15 | % | 16 | % | | Netbacks ($/boe) | | | | | | | | | | | | Operating netback (1) | 36.17 | | 25.90 | | 16.29 | | 29.30 | | 16.94 | | | Fund flows from operations netback | 33.27 | | 22.04 | | 12.95 | | 25.75 | | 13.63 | | | Operating expenses | 13.21 | | 12.72 | | 10.21 | | 12.93 | | 11.55 | | | General and administration expenses | 1.56 | | 1.46 | | 1.35 | | 1.53 | | 1.57 | | | Average reference prices and foreign exchange rates | | | | | | | | | | | | WTI (US $/bbl) | 70.56 | | 66.07 | | 40.93 | | 64.82 | | 38.32 | | | Edmonton Sweet index (US $/bbl) | 66.49 | | 62.96 | | 37.42 | | 60.68 | | 32.57 | | | Saskatchewan LSB index (US $/bbl) | 66.35 | | 62.71 | | 37.57 | | 60.63 | | 32.53 | | | Dated Brent (US $/bbl) | 73.47 | | 68.83 | | 43.00 | | 67.73 | | 40.82 | | | AECO ($/mcf) | 3.60 | | 3.09 | | 2.24 | | 3.28 | | 2.09 | | | NBP ($/mcf) | 20.21 | | 10.92 | | 3.67 | | 13.32 | | 3.43 | | | TTF ($/mcf) | 20.65 | | 10.76 | | 3.51 | | 13.27 | | 3.38 | | | CDN $/US $ | 1.26 | | 1.23 | | 1.33 | | 1.25 | | 1.35 | | | CDN $/Euro | 1.49 | | 1.48 | | 1.56 | | 1.50 | | 1.52 | | | Share information ('000s) | | | | | | | | | | | | Shares outstanding - basic | 161,985 | | 161,893 | | 158,308 | | 161,985 | | 158,308 | | | Shares outstanding - diluted (1) | 169,012 | | 168,903 | | 163,800 | | 169,012 | | 163,800 | | | Weighted average shares outstanding - basic | 161,957 | | 161,546 | | 158,307 | | 160,809 | | 157,688 | | | Weighted average shares outstanding - diluted (1) | 164,991 | | 165,034 | | 158,307 | | 163,693 | | 157,688 | |
| (1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. | | (2) | Prior period comparatives have been revised. Net debt is defined as long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current lease liabilities). | | (3) | Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion and Analysis for disclosure by product type. |
Message to Shareholders
Global commodity prices continued to strengthen during the third quarter which we were able to take advantage of through our internationally diversified asset base. Compared to the previous quarter, global oil prices increased approximately 7%, Canadian natural gas prices increased by 24%, United States natural gas prices increased by 42%, while European natural gas prices (TTF) increased over 90%. Vermilion's exposure to global commodity prices is what sets us apart from our North American peers. Not only does this global commodity exposure enhance our revenue and cash flow during strong market cycles, but it also serves to reduce cash flow volatility over the long-term.
As a result of the strong commodity prices, we generated $263 million of FFO in Q3 2021, representing a 52% increase over the prior quarter. We invested $66 million in E&D capital expenditures during the quarter, resulting in $196 million of FCF (1) with the majority of that FCF used to reduce debt and the remainder allocated to an acquisition in the United States as well as reclamation and abandonment expenditures.
Based on the forward commodity strip, we expect to generate in excess of $500 million , or over $3.00 per share, of free cash flow in 2021 and exit 2021 with net debt forecast to be in the range of $1.65 billion . Based on these projections, this would imply a net debt to trailing FFO ratio of approximately 1.8 times which is well ahead of the original net debt target that we had at the beginning of the year as stronger commodity prices have enabled us to accelerate our debt reduction.
We now have a clear line of sight to achieving our targeted debt to trailing FFO ratio of 1.5 times or less in 2022, and with that we plan to reinstate a dividend in Q1 2022. Although it is still subject to board approval, our intention is to reinstate a fixed quarterly dividend (5-10% of FFO stress-tested at lower prices including US$55 /bbl WTI) while continuing to focus on debt reduction. As further debt targets are achieved we will consider augmenting our return of capital through fixed dividend increases, share buybacks and/or special dividends. We will provide more details on our return of capital framework with our formal 2022 budget release in early December.
Q3 2021 Operations Review
During Q3 2021 we achieved average production of 84,633 boe/d which was down slightly from the previous quarter primarily due to planned maintenance activity. We completed the majority of our planned annual maintenance in Canada and Ireland during the third quarter. The impact from this was partially offset by higher production in the Netherlands , Germany , Australia and United States , including the contribution from a small bolt-on acquisition in the Powder River Basin.
Production from our North American assets averaged 57,022 boe/d in Q3 2021, a decrease of 2% from the prior quarter primarily due to planned and unplanned downtime in Canada , which was partially offset by strong performance from our United States business unit. Production from the United States increased by approximately 2,100 boe/d compared to the previous quarter due to strong performance from our Q2 2021 drilling program and the contribution from a bolt-on acquisition completed during the quarter.
In Canada , we continued with our two-rig drilling program in southeast Saskatchewan where we drilled 19 (19.0 net) wells and completed 20 (19.5 net) wells in the quarter. Activity in Alberta was primarily focused on plant turnarounds and maintenance and preparing for our Q4 2021 condensate-rich Mannville gas drilling program. Our operations were also affected by an unplanned outage at the Plains Midstream Fort Saskatchewan facility late in the quarter, but we were able to minimize the impact by optimizing our marketing logistics and rerouting some of our production to other facilities. The net impact for Q3 2021 related to this event was approximately 550 boe/d; however, most of our production has since been restored and we expect minimal impact on our full year production results.
In the United States , we completed and brought on production the remaining two (2.0 net) wells from our four (4.0 net) well Q2 2021 drilling program. We continue to enhance our knowledge of the Turner play while optimizing our drilling and completion execution. The results from our 2021 drilling program have exceeded expectations from both a cost and production performance basis. With our growing knowledge of this play and region, we were able to identify and execute a strategic acquisition during Q3 2021. The acquisition includes 20,000 net acres of land adjacent to our Hilight field in Wyoming with current production of approximately 1,500 boe/d (72% liquids), and we have identified up to 40 drilling locations in the Turner sands. With an operating netback in excess of $45 /boe based on current commodity prices, the acquired assets are free cash flow positive and are expected to self-fund Turner development over the next 5+ years. In addition, we believe the acquired acreage is prospective for the Niobrara and Parkman formations based on our initial assessment and recent positive results by nearby industry peers. We are optimistic about the future development potential of these plays and will continue to evaluate our prospective land while monitoring industry activity. The acquisition complements our existing asset base by extending our Turner drilling inventory while providing longer-term resource potential from the emerging Niobrara and Parkman formations. Total consideration for the acquisition was US$76 million which was funded through our credit facility. The acquisition is expected to add approximately 600 boe/d in 2021.
Production from our International assets averaged 27,612 boe/d in Q3 2021, a decrease of 1% from the prior quarter primarily due to a three-week planned turnaround in Ireland . The turnaround was successfully completed in July and production resumed in August. Most of the impact from the planned turnaround in Ireland was offset by new production added in the Netherlands and Germany and strong operational uptime in Australia . The 20-day planned turnaround in Australia was deferred from Q3 2021 to Q4 2021 to optimize work schedules.
Most of the activity in Europe during the third quarter was focused on completing and tying in the Nijega (1.0 net) and Blesdijke (0.5 net) gas wells in the Netherlands and the Burgmoor Z-5 gas well (46% working interest) in Germany . In the Netherlands , the Nijega well (1.0 net) was tied in during the third quarter, while the Blesdijke well (0.5 net) is currently undergoing stimulation operations and is expected to be tested in Q4 2021. In Germany , the Burgmoor Z-5 well (46% working interest) was brought on production during the third quarter.
We continue to advance our exploration initiatives in Europe through the acquisition of additional 3D seismic in the Netherlands and Croatia . With the ongoing evaluation of our land base across the CEE, we have been able to hone in our focus on the most prospective regions while relinquishing other blocks that are not deemed as prospective. Progress on the gas plant for the SA-10 block in Croatia also continued during the quarter. We took physical delivery of the gas plant that was shipped from the Netherlands and we continue to advance the detailed design work with construction planned for 2022 and first production anticipated in 2023.
2021 Capital Budget and Production Guidance Increase
When we announced our 2021 capital budget of $300 million earlier this year, we indicated that our primary focus for 2021 was to maximize free cash flow and reduce debt, while retaining the flexibility to adjust investment levels depending on commodity prices. As commodity prices have been much stronger than we anticipated, we have been able to exceed our debt reduction target for the year. As a result, our board of directors have approved a $75 million increase to our 2021 capital program to $375 million . The incremental capital investment will be primarily directed towards our Alberta condensate-rich natural gas and Saskatchewan light oil drilling programs and seismic acquisitions in Europe . In Saskatchewan , we will extend our 2H 2021 drilling program by keeping one rig active through the end of the year which will add 8 (8.0 net) wells. In Alberta , we have advanced the completion date for 9 (8.6 net) condensate-rich Mannville gas wells into Q4 2021 which were originally planned for Q1 2022. Accelerating this capital into Q4 2021 has allowed us to secure our preferred drilling and completion vendors while also improving overall capital efficiencies by executing the majority of this program in Q4 2021 compared to the busier winter months of 2022. This capital efficiency improvement will help offset some of the inflation that we are seeing in our program costs. As a result of the strong production achieved year-to-date, combined with the US acquisition completed in Q3 2021, we have increased our 2021 annual production guidance to 84,500 - 85,500 boe/d.
Preliminary 2022 Outlook
We continue to work through our 2022 budgeting process and expect to announce a formal 2022 budget and guidance in early December. We are targeting a capital program that will deliver a production base similar to our original 2021 guidance of 83,000 to 85,000 boe/d. Our preliminary capital plans for 2022 contemplate a two-well drilling program in Australia as well as continued strategic investment into Europe to expand our business. In order to achieve our production goals, execute our Australian drilling program and deliver on our strategic capital investment to support long-term FCF generation and accommodate anticipated inflation in our cost structure, we anticipate a 2022 capital program in the range of $400 - $450 million . Based on this targeted capital and production range and using forward strip pricing for 2022, we anticipate FCF in excess of $600 million with net debt in the range of $1 billion by the end of the year, implying a net debt to trailing FFO ratio of less than 1.0 times. We will continue to monitor commodity prices, progress on debt reduction and adjust our capital allocation plan as necessary.