Register for real-time alerts, custom portfolio, and market movers
| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| STEP Energy Services Ltd | TSX:STEP | Toronto | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 5.16 | 5.13 | 5.18 | 0 | 00:00:00 |
From Nov 2022 to Nov 2024
CONSOLIDATED HIGHLIGHTS
FINANCIAL REVIEW
| ($000s except percentages and per share amounts) | Three months ended | Nine months ended | ||||||||||
| September 30, | September 30, | September 30, | September 30, | |||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Consolidated revenue | $ | 255,235 | $ | 245,085 | $ | 750,676 | $ | 737,624 | ||||
| Net income | $ | 20,734 | $ | 30,852 | $ | 55,663 | $ | 78,089 | ||||
| Per share-basic | $ | 0.29 | $ | 0.45 | $ | 0.77 | $ | 1.14 | ||||
| Per share-diluted | $ | 0.28 | $ | 0.43 | $ | 0.74 | $ | 1.09 | ||||
| Adjusted EBITDA(1) | $ | 52,286 | $ | 58,050 | $ | 145,142 | $ | 150,290 | ||||
| Adjusted EBITDA %(1) | 21% | 24% | 19% | 20% | ||||||||
| Free Cash Flow(1) | 37,121 | 40,076 | 87,269 | 89,416 | ||||||||
(1) Adjusted EBITDA and Free Cash Flow are non-IFRS financial measures, Adjusted EBITDA % is a non-IFRS financial ratio. These metrics are not defined and have no standardized meaning under IFRS. See Non-IFRS Measures and Ratios.
OPERATIONAL REVIEW
| ($000s except days, proppant, pumped, horsepower and units) | Three months ended | Nine months ended | ||||||
| September 30, | September 30, | September 30, | September 30, | |||||
| 2023 | 2022 | 2023 | 2022 | |||||
| Fracturing services | ||||||||
| Fracturing operating days(2) | 407 | 444 | 1,273 | 1,566 | ||||
| Proppant pumped (tonnes) | 589,000 | 478,000 | 1,693,000 | 1,776,000 | ||||
| Fracturing crews | 8 | 8 | 8 | 8 | ||||
| Dual fuel horsepower (“HP”), ended | 205,250 | 182,750 | 205,250 | 182,750 | ||||
| Total HP, ended | 478,750 | 490,000 | 478,750 | 490,000 | ||||
| Coiled tubing services | ||||||||
| Coiled tubing operating days(2) | 1,311 | 1,199 | 3,713 | 3,187 | ||||
| Active coiled tubing units, ended | 21 | 19 | 21 | 19 | ||||
| Total coiled tubing units, ended | 35 | 33 | 35 | 33 | ||||
(2) An operating day is defined as any coiled tubing or fracturing work that is performed in a 24-hour period, exclusive of support equipment.
| ($000s except shares) | September 30 | December 31, | |||
| 2023 | 2022 | ||||
| Cash and cash equivalents | $ | 1,486 | $ | 2,785 | |
| Working Capital (including cash and cash equivalents)(1) | $ | 72,443 | $ | 66,580 | |
| Total assets | $ | 670,249 | $ | 682,532 | |
| Total long-term financial liabilities(1) | $ | 124,673 | $ | 168,746 | |
| Net Debt(1) | $ | 89,750 | $ | 142,224 | |
| Shares outstanding | 72,233,064 | 71,589,626 | |||
(1) Working Capital, Total long-term financial liabilities and Net Debt are non-IFRS financial measures. They are not defined and have no standardized meaning under IFRS. See Non-IFRS Measures and Ratios.
THIRD QUARTER 2023 HIGHLIGHTS
THIRD QUARTER 2023 OVERVIEW The third quarter of 2023 continued the trend of positive financial results since the first quarter of 2022. Revenue of $255.2 million and Adjusted EBITDA of $52.3 million were driven by solid performance across all service lines. Despite the unstable market environment, the Adjusted EBITDA in Q3 2023 was the best quarterly financial results for the current year. While Adjusted EBITDA showed a modest decline year over year, it showed a slight improvement sequentially as a result of improved activity in the Canadian fracturing and U.S. coiled tubing segments of our business.
Commodity prices stabilized in the third quarter after a volatile second quarter. West Texas Intermediate (WTI), the benchmark U.S. oil price, rose from approximately $70 per barrel at the start of the quarter to approximately $90 per barrel at the close. Strong global demand coupled with cuts from the Organization of the Petroleum Exporting Countries (“OPEC”) finally began to impact the physical oil market, driving the price of crude oil higher. U.S. natural gas prices rallied approximately 20% quarter over quarter, with the benchmark Henry Hub natural gas price responding to the drop off in drilling activity. The U.S. land rig count continued to slide, declining 10% from Q2 to an average count of 630 rigs in Q3 20231. The average Q3 2023 rig count in the Permian basin, home of STEP’s three U.S. fracturing crews, was 326 rigs, down 24 rigs since Q2 20231. Rig counts in Canada increased to 187 rigs in Q3 2023 from 116 in Q2 20231.
STEP’s Canadian fracturing service line had another solid quarter, despite residual impacts from wildfires and floods in Q2 that delayed operations to start the third quarter. The Canadian fracturing service line generated $127.4 million in revenue on 308,000 tonnes of proppant pumped, the best third quarter in the Company’s history. Activity in the U.S. fracturing service line was down sequentially on weak client activity at the start of the quarter but finished strong with all three fracturing fleets fully utilized.
U.S. coiled tubing continues to demonstrate the advantages of scale in that business, setting another quarterly record for operating days while generating $50.0 million in revenue for the quarter. STEP shifted units to capitalize on the higher demand northern regions during the quarter. Clients in these regions have been very receptive to STEP’s technical competency and fleet capability, laying a strong foundation for growth in these areas in 2024. The U.S. coiled tubing division also set a depth record of 8,253 meters (27,075 feet) for a client in the Permian Basin. Canadian coiled tubing levels were sequentially higher in Q3, although decisions by some clients to shift budgets from 2023 to 2024 negatively impacted the service line in the quarter. Early in Q4 2023, the Canadian coiled tubing division also set a depth record, reaching 8,101 meters (26,578 feet) for a client in the Duvernay.
Net income was $20.7 million in Q3 2023 ($0.28 diluted earnings per share), sequentially higher than the $15.3 million in Q2 2023 ($0.21 diluted earnings per share) and lower than the $30.9 million in Q3 2022 ($0.43 diluted earnings per share). Net income included $2.9 million in finance costs (Q2 2023 ‐ $2.8 million, Q3 2022 ‐ $1.3 million) and $4.0 million in share‐based compensation expense (Q2 2023 ‐ $1.4 million, Q3 2022 ‐ $1.4 million).
Free Cash Flow was $37.1 million in Q3 2023, sequentially higher than the $34.8 million in Q2 2023 but lower than the $40.1 million in Q3 2022. This strong Free Cash Flow enabled STEP to reduce Net Debt to $89.8 million at the close of Q3 2023 from $115.8 million at close of Q2 2023, achieving its year-end target of sub-$100 million one quarter early. This debt reduction was accomplished while investing $27.6 million into capital expenditures during Q3 2023. STEP has now reduced debt by nearly $230 million from peak levels in 2018. The reduction in debt and improvement in Adjusted EBITDA resulted in a 12-month trailing Funded Debt to Adjusted Bank EBITDA of 0.56:1.00, well under the limit of 3.00:1 in the Company’s Credit Facilities (as defined in Capital Management – Debt below).______________________________1 Baker Hughes North American Rotary Rig Count, September 29, 2023
MARKET OUTLOOK Oil prices are expected to remain volatile in the near term, as recessionary concerns over the macro economic outlook are being overshadowed by geopolitical events in Europe and the Middle East. Notwithstanding immediate geopolitical tensions, the tight supply demand balance is anticipated to continue into 2024, as OPEC balances production to maintain a target price of $80-$90 per barrel for Brent crude, while remaining sensitive to inflationary concerns in the world’s leading economies. This strategy provides price support for North American producers to moderately increase their capital programs for 2024.
Near term natural gas prices are expected to rise with the seasonal demand for winter heating in both Canada and the U.S. 2024 prices are expected to increase modestly relative to 2023 levels but will remain relatively range-bound until additional liquefied natural gas (LNG) capacity under construction in Canada and the U.S. is completed in the second half of the year. Economics of Canadian gas production are boosted by the price for natural gas liquids (NGL), particularly for diluent. Prices for NGLs are correlated more closely to oil prices, creating attractive returns for NGL-focused producers.
The long-term outlook for 2025 and onward for oilfield services is very constructive. The recent Supreme Court of Canada reference ruling that found the Impact Assessment Act (Bill C-69) and the related regulations to be unconstitutional in part may be a positive signal for Canadian energy production. While not binding on the federal government, it may create an opportunity for Canada to develop a policy framework that recognizes climate concerns while supporting an energy industry that is among the most environmentally sensitive in the world.
Creating a North American regulatory framework to unleash the power of clean, safe and secure energy, particularly LNG, will immediately lower emissions and improve living standards across the world, while continuing to advance global climate goals. STEP is proud to be part of an energy industry in Canada and the U.S., countries that have the natural resources, the regulatory frameworks, and the technical expertise to deliver safe and affordable energy to the world.
Canada As with most years, Canadian Q4 activity levels are expected to show a sequential decline as client budget exhaustion and seasonal holiday activity begins to slow activity in the basin. Despite stronger commodity prices, producers are not expected to materially add to their 2023 budgets, preferring instead to maintain tight capital discipline to support shareholder return frameworks. Fracturing job mix is expected to see a higher mix of smaller jobs, resulting in less efficient activity levels through the quarter. Coiled tubing activity is anticipated to remain steady until the seasonal slowdown begins in early to mid-December.
STEP will use the moderating of activity in Q4 2023 to complete more intensive maintenance on equipment to prepare it for the extremely intensive utilization anticipated for Q1 2024. STEP also has the flexibility to redeploy professionals from operating fracturing equipment to operating sand transport trucks, reducing the payroll burden during slower periods while also reducing logistics costs. STEP has one of western Canada’s largest sand hauling fleets, a critical advantage in the basin that is often tight for sand hauling capacity.
Activity in 2024 is expected to increase, with multiple clients signalling that their 2024 capital budgets will be higher than 2023. The discipline in global oil markets and anticipated completion of the Trans Mountain pipeline project and the Coastal Gas Link pipeline/LNG Canada projects are creating an opportunity for Canada to materially increase production in 2024. Demand for oil and gas is projected to continue growing, creating an opportunity for Canada to deliver among the most sustainably produced energy in the world. STEP is similarly committed to sustainability, introducing its first Tier 4 dual fuel fracturing fleet in 2023. In response to strong client demand for this equipment, which displaces up to 85% of diesel with cleaner burning natural gas, STEP will upgrade an additional fleet with Tier 4 dual fuel technology, with anticipated completion in Q2 2024.
The first quarter fracturing schedule is almost fully booked, supported by an expected incremental year over year increase in work scope following the award of a two-year fracturing service and ancillary services agreement from a leading Montney gas producer. First quarter sand volumes are expected to hit record levels, making sand logistics critical to meeting client expectations in the quarter. STEP has an industry leading sand hauling and logistics capability, which it will continue to invest into through 2024 to meet client demand. The demand for fracturing equipment will likely also exceed STEP’s Canadian fleet capacity, necessitating the transfer of some U.S. fracturing equipment to Canada. STEP’s geographic diversity creates flexibility to move equipment between countries to capitalize on opportunities that deliver the highest return, a key competitive advantage for STEP.
Demand for coiled tubing is expected to grow in 2024. Since inception, STEP pursued a differentiation strategy of bringing the most technically capable equipment and crews to client locations. STEP’s equipment is purpose built for the deepest, most technically challenging wells found in the Montney and Duvernay, which are key growth areas that underpin Canada’s LNG feedstock. The recent competitor consolidation is expected to drive positive change in the coiled tubing market, bringing more price discipline and will more clearly delineate STEP’s value proposition.
United StatesU.S. land rig counts have steadily declined from 756 at the start of 2023 to 603 at the close of Q3 2023, a decline of 20%. Fracturing spreads have fluctuated more dramatically through the year, with intra-quarter peak-to-trough declines of approximately 17% but only an overall decline of 1% from the start of 2023 to the close of Q3 2023. The tightening of the rig count to frac spread ratio has resulted in a short-term oversupply in Q4 2023, putting pressure on pricing for spot market opportunities. STEP has two fracturing crews committed with longer term clients through to the close of 2023, with the third crew likely to remain utilized until late in the quarter before being transferred to Canada.
STEP’s 12 coiled tubing units are anticipated to remain highly utilized for much of the quarter, although the holiday season is likely to affect efficiencies in November and December. STEP’s performance in the northern basins continues to outpace many of the existing competitors that are unable to bring the technology and equipment that comes with the STEP service offering. The consolidation in the premium coiled tubing market has been supportive for pricing in these regions, maintaining rates at more consistent levels. As the Permian and Eagle Ford basins remain under pressure due to equipment oversupply, STEP has transferred coiled tubing units from these areas to the northern basins in order to capitalize on the opportunities that exist in those areas.
Sustained oil prices in the $80-$90 per barrel range are expected to drive a modest recovery in rig counts through the first half of the year, particularly in the Permian, home of STEP’s fracturing crews and four of its twelve coiled tubing fleets. The ongoing capacity constraints within the U.S. natural gas transportation, storage and liquefaction system are not expected to improve until the second half of the year, which may result in uneven fracturing activity levels in the first half of the year. The second half of the year is expected to see the completion of additional LNG capacity on the Gulf Coast, which should provide an additional source of demand for U.S. natural gas oriented fracturing activity.
ConsolidatedSTEP’s focus for the balance of 2023 and into 2024 is on the generation of Free Cash Flow while continuing to invest in emission reducing technologies on our asset base, including the recently deployed Tier 4 dual fuel engines in our Canadian and U.S. fracturing fleet. The strong results posted year to date support the Company’s goals to reduce its balance sheet leverage and make disciplined investments that support STEP’s goal of building a resilient company and creating shareholder value.
CANADIAN FINANCIAL AND OPERATIONS REVIEW
STEP has a fleet of 16 coiled tubing units in the WCSB, all of which are designed to service the deepest wells in the basin. STEP’s fracturing business primarily focuses on the deeper, more technically challenging plays in Alberta and northeast British Columbia. STEP deploys or idles coiled tubing units and fracturing horsepower as dictated by the market’s ability to support targeted utilization and economic returns.
| ($000’s except per day, days, units, proppant pumped and HP) | Three months ended | Nine months ended | ||||||||||
| September 30, | September 30, | September 30, | September 30, | |||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Revenue: | ||||||||||||
| Fracturing | $ | 127,415 | $ | 110,991 | $ | 378,784 | $ | 370,518 | ||||
| Coiled tubing | 30,241 | 30,100 | 89,224 | 82,494 | ||||||||
| 157,656 | 141,091 | 468,008 | 453,012 | |||||||||
| Expenses | 125,414 | 112,213 | 375,512 | 374,536 | ||||||||
| Results from operating activities | $ | 32,242 | $ | 28,878 | $ | 92,496 | $ | 78,476 | ||||
| Adjusted EBITDA(1) | $ | 41,235 | $ | 40,895 | $ | 119,401 | $ | 112,473 | ||||
| Adjusted EBITDA %(1) | 26% | 29% | 26% | 25% | ||||||||
| Sales mix (% of segment revenue) | ||||||||||||
| Fracturing | 81% | 79% | 81% | 82% | ||||||||
| Coiled tubing | 19% | 21% | 19% | 18% | ||||||||
| Fracturing services | ||||||||||||
| Number of fracturing operating days(2) | 250 | 271 | 771 | 945 | ||||||||
| Proppant pumped (tonnes) | 308,000 | 234,000 | 914,000 | 915,000 | ||||||||
| Stages completed | 3,268 | 4,006 | 10,165 | 11,881 | ||||||||
| Fracturing crews | 5 | 5 | 5 | 5 | ||||||||
| Coiled tubing services | ||||||||||||
| Number of coiled tubing operating days(2) | 448 | 536 | 1,368 | 1,468 | ||||||||
| Active coiled tubing units, end of period | 9 | 8 | 9 | 8 | ||||||||
| Total coiled tubing units, end of period | 16 | 16 | 16 | 16 | ||||||||
(1) Adjusted EBITDA is a non-IFRS financial measure and Adjusted EBITDA % are non-IFRS financial ratios. They are not defined and have no standardized meaning under IFRS. See Non-IFRS Measures and Ratios.(2) An operating day is defined as any coiled tubing or fracturing work that is performed in a 24-hour period, exclusive of support equipment.
THIRD QUARTER 2023 COMPARED TO THIRD QUARTER 2022Revenue for the three months ended September 30, 2023 was $157.7 million compared to $141.1 million for the same period of the prior year. Increased intensity on fracturing jobs resulted in higher daily average revenue year-over-year despite continued pricing pressure. This was partially offset by reduced operating days which decreased to 250 for Q3 2023 from 271 during the same period of 2022. Residual effects from the fire and flood conditions during Q2 slowed drilling activity which impacted timing for completion services. STEP remains focused on proper client alignment which contributed to steady utilization in the coiled tubing business during the quarter, however overall days decreased to 448 for Q3 2023 from 536 during the comparable period of 2022. Coiled tubing revenue was also impacted by client delays to start the quarter however an increase in ancillary services contributed to revenue remaining flat year-over-year.
Adjusted EBITDA for the third quarter of 2023 was $41.2 million (26% of revenue) versus $41.0 million (29% of revenue) in the third quarter of 2022. While Adjusted EBITDA increased slightly, year-over-year Adjusted EBITDA % fell slightly due to the change in job mix.
NINE MONTHS ENDED SEPTEMBER 30, 2023 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2022Revenue for the nine months ended September 30, 2023 was $468.0 million compared to $453.0 million for the nine months ended September 30, 2022. Revenue increased compared to the prior year despite decreasing activity levels as changes in client mix and work scope has improved average daily revenue even with continued pressure on pricing. Fracturing operating days decreased to 771 for the first nine months of 2023 from 945 during the same period of 2022. The general decline in market activity as a result of lower natural gas prices combined with fire and flood conditions during Q2 and Q3 were the primary reasons for declining activity year-over-year. The same conditions contributed to the decline in coiled tubing operating days from 1,468 for the first nine months of 2022 to 1,368 for the comparable period of 2023. An increase in ancillary services contributed to an increase of total coiled tubing revenue year-over-year.
The Company’s Canadian operating expenses were relatively flat as cost management remains a focus. Despite these efforts, the higher inflationary environment combined with continued supply chain disruptions, commodity price appreciation, and strong industry activity has costs escalating across most expense categories.
Canadian operations generated Adjusted EBITDA of $119.4 million (26% of revenue) for the first nine months of 2023 compared to $112.5 million (25% of revenue) in the same period of 2022. Continued cost management while retaining pricing improvements achieved since 2022 was the most significant factor in the $6.9 million increase in Adjusted EBITDA. The margin improvement provides the critical cash flow needed to reinvest into the business to ensure that clients receive the best equipment on their well sites.
UNITED STATES FINANCIAL AND OPERATIONS REVIEW
STEP has a fleet of 19 coiled tubing units in the Permian and Eagle Ford basins in Texas, the Bakken shale in North Dakota, and the Uinta-Piceance and Niobrara-DJ basins in Colorado while the U.S. fracturing business primarily operates in the Permian basin in Texas. The Company deploys or idles coiled tubing units and fracturing horsepower as dictated by the market’s ability to support targeted utilization and economic returns.
| ($000’s except per day, days, units, proppant pumped and HP) | Three months ended | Nine months ended | ||||||||||
| September 30, | September 30, | September 30, | September 30, | |||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Revenue: | ||||||||||||
| Fracturing | $ | 47,579 | $ | 67,794 | $ | 145,544 | $ | 199,035 | ||||
| Coiled tubing | 50,000 | 36,200 | 137,124 | 85,577 | ||||||||
| 97,579 | 103,994 | 282,668 | 284,612 | |||||||||
| Expenses | 94,464 | 91,034 | 280,819 | 265,788 | ||||||||
| Results from operating activities | $ | 3,115 | $ | 12,960 | $ | 1,849 | $ | 18,824 | ||||
| Adjusted EBITDA(1) | $ | 15,356 | $ | 20,814 | $ | 38,504 | $ | 50,958 | ||||
| Adjusted EBITDA %(1) | 16% | 20% | 14% | 18% | ||||||||
| Sales mix (% of segment revenue) | ||||||||||||
| Fracturing | 49% | 65% | 51% | 70% | ||||||||
| Coiled tubing | 51% | 35% | 49% | 30% | ||||||||
| Fracturing services | ||||||||||||
| Number of fracturing operating days(2) | 157 | 173 | 502 | 621 | ||||||||
| Proppant pumped (tonnes) | 281,000 | 244,000 | 779,000 | 861,000 | ||||||||
| Stages completed | 1,328 | 1,121 | 3,767 | 3,678 | ||||||||
| Fracturing crews | 3 | 3 | 3 | 3 | ||||||||
| Coiled tubing services | ||||||||||||
| Number of coiled tubing operating days(2) | 863 | 663 | 2,345 | 1,719 | ||||||||
| Active coiled tubing units, end of period | 12 | 11 | 12 | 11 | ||||||||
| Total coiled tubing units, end of period | 19 | 17 | 19 | 17 | ||||||||
(1) Adjusted EBITDA is a non-IFRS financial measure and Adjusted EBITDA % is non-IFRS financial ratios. They are not defined and have no standardized meaning under IFRS. See Non-IFRS Measures and Ratios.(2) An operating day is defined as any coiled tubing or fracturing work that is performed in a 24-hour period, exclusive of support equipment.
THIRD QUARTER 2023 COMPARED TO THIRD QUARTER 2022Revenue for the three months ended September 30, 2023 was $97.6 million compared to $104.0 million at September 30, 2022. The increase in active coiled tubing units and resultant increase in operating days offset much of the declines in fracturing revenue resulting from the transition to client-supplied product. Key acquisitions in 2022 have enabled STEP to deploy additional coiled tubing units to key basins and benefit from strong oilfield activity levels in those regions. Proper client alignment within the coiled tubing business has been a main driver to our continued success in this segment as operating days increased to 863 for Q3 2023 from 663 during the comparable period of 2022. Fracturing activity stabilized in the third quarter however market conditions have continued to put pressure on pricing compared to the prior year.
U.S. operations generated Adjusted EBITDA of $15.4 million (16% of revenue) for the third quarter 2023 versus $20.8 million (20% of revenue) in the third quarter of 2022. While coiled tubing rates have remained stable, the change in job mix and downward pressure on rates for fracturing services were the primary contributors to the drop in Adjusted EBITDA compared to the prior year.
NINE MONTHS ENDED SEPTEMBER 30, 2023 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2022Revenue for the nine months ended September 30, 2023 was $282.7 million compared to $284.6 million for the nine months ended September 30, 2022. U.S. operations realized a 36% increase in operating days for the coiled tubing service line reflecting the additional assets acquired during 2022 that increased our depth capacity and allowed us to expand our operating footprint. Operating days across the Company’s U.S. fracturing operations were relatively flat at 3,767 for the first nine months of 2023 compared to 3,678 days during the same period of 2022, however, the transition to client supplied product resulted in significantly lower revenue.
The year over year increase in operating expenses reflects increased maintenance costs from the increase in fracturing intensity compared to the prior year and from the intensive preventative maintenance program completed during the first quarter of 2023. Inflationary pressures and supply chain constraints have eased slightly during Q3 2023, but costs remain higher on a year over year basis across most expense categories.
U.S. operations generated Adjusted EBITDA of $38.5 million (14% of revenue) for the nine months ended September 30, 2023, compared to an Adjusted EBITDA of $51.0 million (18% of revenue) for the nine months ended September 30, 2022. The transition to client supplied product and declining fracturing rates were the primary contributors to the Adjusted EBITDA decline and were partially offset by improved activity in coiled tubing.
CORPORATE FINANCIAL REVIEW The Company’s corporate activities are separated from Canadian and U.S. operations. Corporate operating expenses include expenses related to asset reliability and optimization teams, as well as general and administrative costs which include costs associated with the executive team, the Board of Directors, public company costs and other activities that benefit the Canadian and U.S. operating segments collectively.
| ($000’s) | Three months ended | Nine months ended | ||||||||||
| September 30, | September 30, | September 30, | September 30, | |||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Expenses: | ||||||||||||
| Operating expenses | $ | 490 | $ | 503 | $ | 1,438 | $ | 1,869 | ||||
| Selling, general and administrative | 7,259 | 4,027 | 10,656 | 24,577 | ||||||||
| Results from operating activities | $ | (7,749 | ) | $ | (4,530 | ) | $ | (12,094 | ) | $ | (26,446 | ) |
| Add: | ||||||||||||
| Depreciation | 222 | 151 | 637 | 437 | ||||||||
| Share-based compensation expense (recovery) | 3,322 | 720 | (1,306 | ) | 12,868 | |||||||
| Adjusted EBITDA(1) | $ | (4,205 | ) | $ | (3,659 | ) | $ | (12,763 | ) | $ | (13,141 | ) |
| Adjusted EBITDA %(1) | (2% | ) | (1% | ) | (2% | ) | (2% | ) | ||||
(1) Adjusted EBITDA is a non-IFRS financial measure and Adjusted EBITDA % is a non-IFRS financial ratio. They are not defined and have no standardized meaning under IFRS. See Non-IFRS Measures and Ratios.
THIRD QUARTER 2023 COMPARED TO THIRD QUARTER 2022For the three months ended September 30, 2023, expenses from corporate activities were $7.7 million compared to expenses of $4.5 million for the same period in 2022. The increase in these expenses was primarily due to the mark to market adjustment on cash settled share-based compensation in the current period. Corporate expense were $3.2 million higher in Q3 2023 relative to Q3 2022, as the Company’s share price increased by $0.98 from June 30, 2023 to September 30, 2023 compared to a share price decrease of $0.21 during the same period of the prior year. Adjusted EBITDA of $(4.2) million for the three months ended September 30, 2023 remained aligned with Adjusted EBITDA of $(3.7) million for the same period in 2022.
NINE MONTHS ENDED SEPTEMBER 30, 2023 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2022For the nine months ended September 30, 2023 expenses from corporate activities were $12.1 million compared to $26.4 million for the same period in 2022. Cash settled share-based compensation expense was lower in the first nine months of 2023 as a decrease in number of cash settled instruments outstanding combined with the share price decreasing $1.09 from December 31, 2022 to September 30, 2023 resulted in lower expenses from the mark to market adjustment in the current period. Adjusted EBITDA of $(12.8) million for the nine months ended September 30, 2023 was relatively consistent with Adjusted EBITDA of $(13.1) million for the same period of the prior year.
NON-IFRS MEASURES AND RATIOSThis Press Release includes terms and performance measures commonly used in the oilfield services industry that are not defined under IFRS. The terms presented are intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These non-IFRS measures have no standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. The non-IFRS measures should be read in conjunction with the Company’s quarterly financial statements and Annual Financial Statements and the accompanying notes thereto.
“Adjusted EBITDA” is a financial measure not presented in accordance with IFRS and is equal to net (loss) income before finance costs, depreciation and amortization, (gain) loss on disposal of property and equipment, current and deferred income tax provisions and recoveries, equity and cash settled share-based compensation, transaction costs, foreign exchange forward contract (gain) loss, foreign exchange (gain) loss, and impairment losses. “Adjusted EBITDA %” is a non-IFRS ratio and is calculated as Adjusted EBITDA divided by revenue. Adjusted EBITDA and Adjusted EBITDA % are presented because they are widely used by the investment community as they provide an indication of the results generated by the Company’s normal course business activities prior to considering how the activities are financed and the results are taxed. The Company uses Adjusted EBITDA and Adjusted EBITDA % internally to evaluate operating and segment performance, because management believes they provide better comparability between periods. The following table presents a reconciliation of the non-IFRS financial measure of Adjusted EBITDA to the IFRS financial measure of net income.
| ($000s except percentages) | Three months ended | Nine months ended | |||||||||||
| September 30, | September 30, | September 30, | September 30, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||
| Net income | $ | 20,734 | $ | 30,852 | $ | 55,663 | $ | 78,089 | |||||
| Add (deduct): | |||||||||||||
| Depreciation and amortization | 20,743 | 19,378 | 62,614 | 63,140 | |||||||||
| Gain on disposal of equipment | (417 | ) | (921 | ) | (1,064 | ) | (2,571 | ) | |||||
| Finance costs | 2,850 | 1,330 | 8,557 | 7,551 | |||||||||
| Income tax expense | 6,936 | 6,211 | 18,318 | 20,582 | |||||||||
| Share-based compensation – Cash settled | 2,709 | 396 | (3,713 | ) | 14,441 | ||||||||
| Share-based compensation – Equity settled | 1,336 | 977 | 4,020 | 1,990 | |||||||||
| Foreign exchange (gain) loss | 1,278 | (173 | ) | 2,036 | (224 | ) | |||||||
| Unrealized gain on derivatives | (3,783 | ) | - | (1,289 | ) | - | |||||||
| Impairment reversal | - | - | - | (32,708 | ) | ||||||||
| Adjusted EBITDA | $ | 52,386 | $ | 58,050 | $ | 145,142 | $ | 150,290 | |||||
| Adjusted EBITDA % | 21% | 24% | 19% | 20% | |||||||||
“Free Cash Flow” is a financial measure not presented in accordance with IFRS and is equal to net cash provided by operating activities adjusted for changes in non-cash Working Capital from operating activities, sustaining capital expenditures, term loan principal repayments and lease payments (net of sublease receipts). The Company may deduct or include additional items in its calculation of Free Cash Flow that are unusual, non-recurring or non-operating in nature. Free Cash Flow is presented as this measure is widely used in the investment community as an indication of the level of cash flow generated by ongoing operations. Management uses Free Cash Flow to evaluate the adequacy of internally generated cash flows to manage debt levels, invest in the growth of the business or return capital to shareholders. The following table presents a reconciliation of the non-IFRS financial measure of Free Cash Flow to the IFRS financial measure of net cash provided by operating activities.
| ($000s) | Three months ended | Nine months ended | ||||||||||
| September 30, | September 30, | September 30, | September 30, | |||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Net cash provided by (used in) operating activities | $ | 50,736 | $ | 73,048 | $ | 131,876 | $ | 90,265 | ||||
| Add (deduct): | ||||||||||||
| Changes in non-cash working capital from operating activities | (2,607 | ) | (19,395 | ) | (8,319 | ) | 50,246 | |||||
| Sustaining capital | (8,518 | ) | (11,107 | ) | (30,139 | ) | (30,531 | ) | ||||
| Term loan principal repayments | - | - | - | (13,975 | ) | |||||||
| Lease payments (net of sublease receipts) | (2,490 | ) | (2,470 | ) | (6,149 | ) | (6,589 | ) | ||||
| Free Cash Flow | $ | 37,121 | $ | 40,076 | $ | 87,269 | $ | 89,416 | ||||
“Working Capital”, “Total long-term financial liabilities” and “Net Debt” are financial measures not presented in accordance with IFRS. “Working Capital” is equal to total current assets less total current liabilities. “Total long-term financial liabilities” is comprised of loans and borrowings, long-term lease obligations and other liabilities. “Net Debt” is equal to loans and borrowings before deferred financing charges less cash and cash equivalents and CCS derivatives. The data presented is intended to provide additional information about items on the statement of financial position and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS.
The following table represents the composition of the non-IFRS financial measure of Working Capital (including cash and cash equivalents).
| ($000s) | September 30, | December 31, | |||||
| 2023 | 2022 | ||||||
| Current assets | $ | 233,899 | $ | 256,361 | |||
| Current liabilities | (161,456 | ) | (189,781 | ) | |||
| Working Capital (including cash and cash equivalents) | $ | 72,443 | $ | 66,580 | |||
The following table presents the composition of the non-IFRS financial measure of Total long-term financial liabilities.
| ($000s) | September 30, | December 31, | |||
| 2023 | 2022 | ||||
| Long-term loans | $ | 89,740 | $ | 140,794 | |
| Long-term leases | 18,461 | 13,860 | |||
| Other long-term liabilities | 16,472 | 14,092 | |||
| Total long-term financial liabilities | $ | 124,673 | $ | 168,746 |
The following table presents the composition of the non-IFRS financial measure of Net Debt.
| ($000s) | September 30, | December 31, | |||||
| 2023 | 2022 | ||||||
| Loans and borrowings | $ | 89,740 | $ | 140,794 | |||
| Add back: Deferred financing costs | 1,909 | 2,704 | |||||
| Less: Cash and cash equivalents | (1,486 | ) | (2,785 | ) | |||
| Less: CCS Derivatives liability (asset) | (413 | ) | 1,511 | ||||
| Net Debt | $ | 89,750 | $ | 142,224 |
RISK FACTORS AND RISK MANAGEMENTThe oilfield services industry involves many risks, which may influence the ultimate success of the Company. The risks and uncertainties set out are not the only ones the Company is facing. There are additional risks and uncertainties that the Company does not currently know about or that the Company currently considers immaterial which may also impair the Company’s business operations and can cause the price of the Common Shares to decline. If any of the following risks occur, the Company’s business may be harmed and the Company’s financial condition and results of operations may suffer significantly:
In addition, global and national risks associated with inflation or economic contraction may adversely affect the Company by, among other things, reducing economic activity resulting in lower demand, and pricing, for crude oil and natural gas products, and thereby the demand and pricing for the Company’s services. For additional information regarding the risks that the Company is exposed to, see the disclosure provided under the heading “Risk Factors” in the AIF which is available on the SEDAR website at www.sedar.com and is incorporated by reference herein.
FORWARD-LOOKING INFORMATION & STATEMENTS Certain statements contained in this Press Release constitute “forward-looking statements” or “forward-looking information” within the meaning of applicable securities laws (collectively, “forward-looking statements”). These statements relate to the expectations of management about future events, results of operations and the Company’s future performance (both operational and financial) and business prospects. All statements other than statements of historical fact are forward-looking statements. The use of any of the words “anticipate”, “plan”, “contemplate”, “continue”, “estimate”, “expect”, “intend”, “propose”, “might”, “may”, “will”, “shall”, “project”, “should”, “could”, “would”, “believe”, “predict”, “forecast”, “pursue”, “potential”, “objective” and “capable” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. While the Company believes the expectations reflected in the forward-looking statements included in this Press Release are reasonable, such statements are not guarantees of future performance or outcomes and may prove to be incorrect and should not be unduly relied upon.
In particular, but without limitation, this Press Release contains forward-looking statements pertaining to: 2023, 2024, and 2025 industry conditions and outlook, including the effect of European and Middle East geopolitical events, demand for oil and gas, industry production discipline, and other macroeconomic factors, and the effect of new LNG facilities; OPEC production as it relates to oil prices; anticipated 2023 and 2024 utilization levels, commodity prices, and pricing for the Company’s services; recession risk, including its effect on oil prices; the timing of completion of the Company’s tier 4 dual fuel conversions and anticipated substitution rates in the Company’s dual fuel fleets; the effect of a Canadian Supreme Court reference opinion on the federal Impact Assessment Act and related regulations, and consequently on Canadian energy production; the effect of under-investment in hydrocarbon production; the effect large clients and their programs may have on the Company’s activity levels; supply and demand for the Company’s and its competitors’ services, including the ability for the industry to respond to demand increases; the effect of inflation and related cost increases; the effect of natural gas transportation, storage and liquefaction system constraints; the impact of weather and break up on the Company’s operations; the competitive labour market; the potential for commodity price volatility; the effect of changes in work scope and awards on expected margins and the location of deployed equipment; the Company’s focus on Free Cash Flow and investment in emissions reduction technologies; the Company’s ability to meet all financial commitments including interest payments over the next twelve months; the Company’s plans regarding equipment; the Company’s ability to manage its capital structure; expected debt repayment and Funded Debt to Adjusted Bank EBITDA ratios; expected income tax and derivative liabilities; adequacy of resources to funds operations, financial obligations and planned capital expenditures; the Company’s ability to retain its existing clients; the monitoring of impairment, amount and age of balances owing, and the Company’s financial assets and liabilities denominated in U.S. dollars, and exchange rates; supply chain constraints impact on new-build and refurbishment timelines; and the Company’s expected compliance with covenants under its Credit Facilities and its ability to satisfy its financial commitments thereunder.
The forward-looking information and statements contained in this Press Release reflect several material factors and expectations and assumptions of the Company including, without limitation: the effect of macroeconomic factors, including global energy security concerns and levels of oil and gas inventories; market concerns regarding economic recession; levels of oil and gas production and the effect of OPEC related capacity and related uncertainty on the market for the Company’s services; that the Government of Canada will respond to a Supreme Court reference ruling in a manner consistent with past practice; that the Company will continue to conduct its operations in a manner consistent with past operations; the Company will continue as a going concern; the general continuance of current or, where applicable, assumed industry conditions; pricing of the Company’s services; the Company’s ability to market successfully to current and new clients; predictability of Q4 activity levels; predictable effect of seasonal weather and break up on the Company’s operations; the Company’s ability to utilize its equipment; the Company’s ability to collect on trade and other receivables; Client demand for dual fuel fleets and emissions reduction technologies; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost effective manner; levels of deployable equipment; future capital expenditures to be made by the Company; future funding sources for the Company’s capital program; the Company’s future debt levels; the availability of unused credit capacity on the Company’s credit lines; the impact of competition on the Company; the Company’s ability to obtain financing on acceptable terms; the Company’s continued compliance with financial covenants; the amount of available equipment in the marketplace; and client activity levels and spending. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove correct.
Actual results could differ materially from those anticipated in these forward‐looking statements due to the risk factors set forth under the heading “Risk Factors” in the AIF and under the heading Risk Factors and Risk Management in this Press Release.
Any financial outlook or future orientated financial information contained in this Press Release regarding prospective financial performance, financial position or cash flows is based on the assumptions about future events, including economic conditions and proposed courses of action based on management’s assessment of the relevant information that is currently available. Projected operational information, including the Company’s capital program, contains forward looking information and is based on a number of material assumptions and factors, as are set out above. These projections may also be considered to contain future oriented financial information or a financial outlook. The actual results of the Company’s operations will likely vary from the amounts set forth in these projections and such variations may be material. Readers are cautioned that any such financial outlook and future oriented financial information contains herein should not be used for purposes other than those for which it is disclosed herein.
The forward-looking information and statements contained in this Press Release speak only as of the date of the document, and none of the Company or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws. The reader is cautioned not to place undue reliance on forward-looking information.
CONDENSED CONSOLIDATED INTERIM STATEMENTS OF FINANCIAL POSITION
| As at | September 30, | December 31, | |||||
| Unaudited (in thousands of Canadian dollars) | 2023 | 2022 | |||||
| ASSETS | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 1,486 | $ | 2,785 | |||
| Trade and other receivables | 169,313 | 199,004 | |||||
| Income tax receivable | - | 137 | |||||
| Inventory | 51,619 | 46,410 | |||||
| Prepaid expenses and deposits | 11,068 | 8,025 | |||||
| Risk management contracts | 413 | - | |||||
| 233,899 | 256,361 | ||||||
| Property and equipment | 404,819 | 402,482 | |||||
| Right-of-use assets | 27,227 | 23,528 | |||||
| Intangible assets | 132 | 161 | |||||
| Other assets | 4,172 | - | |||||
| $ | 670,249 | $ | 682,532 | ||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||
| Current Liabilities | |||||||
| Trade and other payables | $ | 137,973 | $ | 165,869 | |||
| Current portion of lease obligations | 8,302 | 8,326 | |||||
| Current portion of other liabilities | 2,654 | 6,526 | |||||
| Income tax payable | 12,527 | 9,060 | |||||
| 161,456 | 189,781 | ||||||
| Deferred tax liabilities | 18,348 | 17,972 | |||||
| Lease obligations | 18,461 | 13,860 | |||||
| Other liabilities | 16,472 | 14,092 | |||||
| Loans and borrowings | 89,740 | 140,794 | |||||
| 304,477 | 376,499 | ||||||
| Shareholders' equity | |||||||
| Share capital | 455,864 | 453,702 | |||||
| Contributed surplus | 34,701 | 32,843 | |||||
| Accumulated other comprehensive income | 16,292 | 16,236 | |||||
| Deficit | (141,085 | ) | (196,748 | ) | |||
| 365,772 | 306,033 | ||||||
| $ | 670,249 | $ | 682,532 | ||||
CONDENSED CONSOLIDATED INTERIM STATEMENTS OF NET INCOME AND OTHER COMPREHENSIVE INCOME
| For the three months endedSeptember 30, | For the nine months endedSeptember 30, | ||||||||||||
| Unaudited(in thousands of Canadian dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||
| Revenue | $ | 255,235 | $ | 245,085 | $ | 750,676 | $ | 737,624 | |||||
| Operating expenses | 214,218 | 198,770 | 639,293 | 623,622 | |||||||||
| Gross profit | 41,017 | 46,315 | 111,383 | 114,002 | |||||||||
| Selling, general and administrative expenses | 13,409 | 9,007 | 29,132 | 43,148 | |||||||||
| Results from operating activities | 27,608 | 37,308 | 82,251 | 70,854 | |||||||||
| Finance costs, net | 2,850 | 1,330 | 8,557 | 7,551 | |||||||||
| Foreign exchange loss (gain) | 1,278 | (173 | ) | 2,036 | (224 | ) | |||||||
| Unrealized gain on derivatives | (3,783 | ) | - | (1,289 | ) | - | |||||||
| Gain on disposal of property and equipment | (417 | ) | (921 | ) | (1,064 | ) | (2,571 | ) | |||||
| Amortization of intangible assets | 10 | 9 | 30 | 135 | |||||||||
| Impairment reversal of property and equipment | - | - | - | (32,708 | ) | ||||||||
| Income before income tax | 27,670 | 37,063 | 73,981 | 98,671 | |||||||||
| Income tax expense | |||||||||||||
| Current | 4,878 | 5,071 | 17,948 | 8,423 | |||||||||
| Deferred | 2,058 | 1,140 | 370 | 12,159 | |||||||||
| Total income tax expense | 6,936 | 6,211 | 18,318 | 20,582 | |||||||||
| Net income | 20,734 | 30,852 | 55,663 | 78,089 | |||||||||
| Other comprehensive income | |||||||||||||
| Foreign currency translation gain | 6,039 | 13,956 | 56 | 17,092 | |||||||||
| Total comprehensive income | $ | 26,773 | $ | 44,808 | $ | 55,719 | $ | 95,181 | |||||
| Net income per share: | |||||||||||||
| Basic | $ | 0.29 | $ | 0.45 | $ | 0.77 | $ | 1.14 | |||||
| Diluted | $ | 0.28 | $ | 0.43 | $ | 0.74 | $ | 1.09 | |||||
CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
| For the three months endedSeptember 30, | For the nine months endedSeptember 30, | ||||||||||||
| Unaudited(in thousands of Canadian dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||
| Operating activities: | |||||||||||||
| Net income | $ | 20,734 | $ | 30,852 | $ | 55,663 | $ | 78,089 | |||||
| Adjusted for the following: | |||||||||||||
| Depreciation and amortization | 20,743 | 19,378 | 62,614 | 63,140 | |||||||||
| Share-based compensation | 4,045 | 1,373 | 307 | 16,431 | |||||||||
| Unrealized foreign exchange loss (gain) | 1,041 | (837 | ) | 3,413 | (812 | ) | |||||||
| Unrealized gain on derivatives | (3,783 | ) | - | (1,289 | ) | - | |||||||
| Gain on disposal of property and equipment | (417 | ) | (921 | ) | (1,064 | ) | (2,571 | ) | |||||
| Impairment reversal of property and equipment | - | - | - | (32,708 | ) | ||||||||
| Finance costs | 2,850 | 1,330 | 8,557 | 7,551 | |||||||||
| Income tax expense | 6,936 | 6,211 | 18,318 | 20,582 | |||||||||
| Income taxes paid | (1,569 | ) | (117 | ) | (14,439 | ) | (161 | ) | |||||
| Cash finance costs paid | (2,451 | ) | (3,616 | ) | (8,523 | ) | (9,030 | ) | |||||
| Changes in non-cash working capital from operating activities | 2,607 | 19,395 | 8,319 | (50,246 | ) | ||||||||
| Net cash provided by operating activities | 50,736 | 73,048 | 131,876 | 90,265 | |||||||||
| Investing activities: | |||||||||||||
| Purchase of property and equipment | (25,232 | ) | (20,226 | ) | (65,606 | ) | (50,322 | ) | |||||
| Proceeds from disposal of equipment and vehicles | 75 | 888 | 2,023 | 5,658 | |||||||||
| Changes in non-cash working capital from investing activities | 2,613 | (5,821 | ) | (9,986 | ) | 103 | |||||||
| Net cash used in investing activities | (22,544 | ) | (25,159 | ) | (73,569 | ) | (44,561 | ) | |||||
| Financing activities: | |||||||||||||
| (Repayment) draws of loans and borrowings | (30,236 | ) | (46,046 | ) | (53,302 | ) | (41,012 | ) | |||||
| Repayment of obligations under finance lease | (2,210 | ) | (3,179 | ) | (6,414 | ) | (7,585 | ) | |||||
| Net cash used in financing activities | (32,446 | ) | (49,225 | ) | (59,716 | ) | (48,597 | ) | |||||
| Impact of exchange rate changes on cash and cash equivalents | 32 | 914 | 110 | 951 | |||||||||
| Decrease in cash and cash equivalents | (4,222 | ) | (422 | ) | (1,299 | ) | (1,942 | ) | |||||
| Cash and cash equivalents, beginning of period | 5,708 | 2,178 | 2,785 | 3,698 | |||||||||
| Cash and cash equivalents, end of period | $ | 1,486 | $ | 1,756 | $ | 1,486 | $ | 1,756 | |||||
ABOUT STEPSTEP is an energy services company that provides coiled tubing, fluid and nitrogen pumping and hydraulic fracturing solutions. Our combination of modern equipment along with our commitment to safety and quality execution has differentiated STEP in plays where wells are deeper, have longer laterals and higher pressures. STEP has a high-performance, safety-focused culture and its experienced technical office and field professionals are committed to providing innovative, reliable and cost-effective solutions to its clients.
Founded in 2011 as a specialized deep capacity coiled tubing company, STEP has grown into a North American service provider delivering completion and stimulation services to exploration and production (“E&P”) companies in Canada and the U.S. Our Canadian services are focused in the Western Canadian Sedimentary Basin (“WCSB”), while in the U.S., our fracturing and coiled tubing services are focused in the Permian and Eagle Ford in Texas, the Uinta-Piceance and Niobrara-DJ basins in Colorado and the Bakken in North Dakota.
Our four core values; Safety, Trust, Execution and Possibilities inspire our team of professionals to provide differentiated levels of service, with a goal of flawless execution and an unwavering focus on safety.
For more information please contact:
| Steve GlanvillePresident and Chief Executive Officer | Klaas DeemterChief Financial Officer | |||
| Telephone: 403-457-1772 | Telephone: 403-457-1772 | |||
| Email: investor_relations@step-es.comWeb: www.stepenergyservices.com | ||||
STEP will host a conference call on Thursday, November 2, 2023 at 9:00 a.m. MT to discuss the results for the Third Quarter of 2023.
To listen to the webcast of the conference call, please click on the following URL:https://viavid.webcasts.com/starthere.jsp?ei=1634848&tp_key=e301297c60.
You can also visit the Investors section of our website at www.stepenergyservices.com and click on “Reports, Presentations & Key Dates”.
To participate in the Q&A session, please call the conference call operator at: 1-888-886-7786 (toll free) 15 minutes prior to the call’s start time and ask for “STEP Energy Services Third Quarter 2023 Earnings Results Conference Call”.
The conference call will be archived on STEP’s website at www.stepenergyservices.com/investors.
1 Year STEP Energy Services Chart |
1 Month STEP Energy Services Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions
Hot Features
Premium
