CALGARY, Alberta, Nov. 02, 2017 (GLOBE NEWSWIRE) —
Financial Results
For the three-month period ended September 30, 2017, PHX Energy (TSX:PHX) generated consolidated revenue of $65.4 million, an increase of 87 percent from $35.0 million in the comparable 2016-period. The Corporation realized a net loss of $0.8 million and adjusted EBITDA (see Non-GAAP Measures) of $12.4 million in the 2017-quarter compared to a net loss of $10.7 million and negative adjusted EBITDA of $0.2 million in 2016. The adjusted EBITDA for the third quarter of 2017 was the highest since the fourth quarter of 2014 and resulted from strengthened consolidated activity levels and average day rates as the directional drilling industry continued to recover from the severe downturn. The Corporation’s activity in the third quarter of 2017 rose by 60 percent to 6,323 consolidated operating days (2016 – 3,942 days) while the consolidated average day rate increased by 18 percent to $10,127 (2016 – $8,599).
During the third quarter, PHX Energy remained heavily focused on the US drilling market, as it presents the greatest opportunities for growth with an average of 876 horizontal and directional rigs running per day (Source: Baker Hughes). The US operating segment generated revenue of $39.3 million in the 2017-quarter, representing 60 percent of the Corporation’s consolidated revenue for the period. The US segment achieved 2,969 operating days in the 2017-quarter, the highest total since the first quarter of 2015 and 24 percent greater than the second quarter of 2017.
The conditions in the Canadian drilling market improved over the prior-year, as the industry’s horizontal and directional drilling activity (measured by drilling days) increased by 89 percent to 18,127 days in the 2017-quarter (Source: Daily Oil Bulletin). The Canadian segment generated revenue of $21.7 million in the 2017-quarter, as activity and day rates grew to 2,795 operating days and $7,424.
As at September 30, 2017, PHX Energy had long-term debt of $15.9 million and working capital of $56.3 million.
Capital Spending
The Corporation incurred $8.9 million in capital expenditures during the third quarter of 2017 (2016 – $2.4 million), which were primarily used to expand the fleet of Velocity Real-Time Systems (“Velocity”), performance drilling motors and electronic drilling recorder (“EDR”) equipment. During the first nine-months of 2017 the Corporation spent a total of $17.4 million (2016 – $5.3 million) on capital expenditures.
As at September 30, 2017, the Corporation had $7.1 million of outstanding capital commitments to purchase drilling and other equipment. These commitments include $3.8 million for Velocity systems, $2.1 million for performance drilling motors, $1.1 million for resistivity while drilling (“RWD”) systems, and $0.1 million of machinery and equipment. The Corporation expects the equipment to be delivered before March 31, 2018.
PHX Energy’s anticipated capital expenditure budget for 2017 remains at $25.0 million.
Normal Course Issuer Bid
The TSX approved PHX Energy’s Normal Course Issuer Bid (“NCIB”) to purchase for cancellation, from time-to-time, up to a maximum of 2,929,494 common shares of the Corporation. Purchases of common shares will be made on the open market through the facilities of the TSX and through alternative trading systems. The price which PHX Energy will pay for any common shares purchased will be at the prevailing market price on the TSX or alternate trading systems at the time of such purchase. The NCIB commenced on June 26, 2017 and will terminate on June 25, 2018 or such earlier time as the NCIB is completed or terminated at the option of the Corporation. Pursuant to the NCIB, 15,600 shares were purchased and cancelled by the Corporation during the third quarter of 2017.
Equity Financing
On February 2, 2017, PHX Energy closed a bought deal financing for aggregate proceeds of $28.8 million. An aggregate of 7,187,500 common shares of the Corporation were issued at a price of $4.00 per common share. Concurrent with the closing of the public offering, certain directors, officers, employees and consultants of PHX Energy purchased a total of 500,000 common shares at a price of $4.00 per share on a private placement basis. The gross proceeds from the public offering and concurrent private placement totaled to approximately $30.8 million.
The proceeds from the equity financing were primarily used to reduce the outstanding loans and borrowings under the Corporation’s credit facility.
(Stated in thousands of dollars except per share amounts, percentages and shares outstanding)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | |||||||||
| Operating Results | (unaudited) | (unaudited) | (unaudited) | (unaudited) | ||||||||||
| Revenue | 65,396 | 34,964 | 87 | 180,340 | 101,772 | 77 | ||||||||
| Net loss | (846 | ) | (10,679 | ) | (92 | ) | (18,401 | ) | (31,442 | ) | (41 | ) | ||
| Loss per share – diluted | (0.01 | ) | (0.21 | ) | (95 | ) | (0.32 | ) | (0.70 | ) | (54 | ) | ||
| Adjusted EBITDA (1) | 12,357 | (232 | ) | n.m. | 17,243 | 1,865 | n.m. | |||||||
| Adjusted EBITDA per share – diluted (1) | 0.21 | – | n.m. | 0.29 | 0.04 | n.m. | ||||||||
| Adjusted EBITDA as a percentage of revenue (1) |
19 | % | (1 | %) | 10 | % | 2 | % | ||||||
| Cash Flow | ||||||||||||||
| Cash flows from (used in) operating activities | (13,684 | ) | (100 | ) | n.m. | (9,910 | ) | 4,732 | n.m. | |||||
| Funds from (used in) operations (1) | 8,436 | (1,894 | ) | n.m. | 12,533 | (1,502 | ) | n.m. | ||||||
| Funds from (used in) operations per share – diluted(1) |
0.14 | (0.04 | ) | n.m. | 0.21 | (0.03 | ) | n.m. | ||||||
| Dividends paid | – | – | – | – | 416 | (100 | ) | |||||||
| Dividends per share (2) | – | – | – | – | 0.01 | (100 | ) | |||||||
| Capital expenditures | 8,900 | 2,365 | n.m. | 17,397 | 5,256 | n.m. | ||||||||
| Financial Position (unaudited) | Sept 30, ‘17 | Dec 31, ‘16 | ||||||||||||
| Working capital | 56,318 | 44,230 | 27 | |||||||||||
| Long-term debt | 15,872 | 29,014 | (45 | ) | ||||||||||
| Shareholders’ equity | 186,122 | 178,387 | 4 | |||||||||||
| Common shares outstanding | 58,574,287 | 50,810,721 | 15 | |||||||||||
n.m. – not meaningful
(1) Refer to non-GAAP measures section that follows the outlook section.
(2) Dividends paid by the Corporation on a per share basis in the period.
Non-GAAP Measures
PHX Energy uses certain performance measures throughout this press release that are not recognizable under Canadian generally accepted accounting principles (“GAAP”). These performance measures include adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”), adjusted EBITDA per share, funds from operations, funds from operations per share, debt to covenant EBITDA ratio and working capital. Management believes that these measures provide supplemental financial information that is useful in the evaluation of the Corporation’s operations and are commonly used by other oil and natural gas service companies. Investors should be cautioned, however, that these measures should not be construed as alternatives to measures determined in accordance with GAAP as an indicator of PHX Energy’s performance. The Corporation’s method of calculating these measures may differ from that of other organizations, and accordingly, these may not be comparable. Please refer to the non-GAAP measures section following the Outlook section for applicable definitions and reconciliations.
Cautionary Statement Regarding Forward-Looking Information and Statements
This document contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “could”, “should”, “can”, “believe”, “plans”, “intends”, “strategy” and similar expressions are intended to identify forward-looking information or statements.
The forward-looking information and statements included in this document are not guarantees of future performance and should not be unduly relied upon. These statements and information 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 and information. The Corporation believes the expectations reflected in such forward-looking statements and information are reasonable, but no assurance can be given that these expectations will prove to be correct. Such forward-looking statements and information included in this document should not be unduly relied upon. These forward-looking statements and information speak only as of the date of this document.
In particular, forward-looking information and statements contained in this document include, without limitation, the delivery of capital expenditure items, the projected capital expenditures budget and how this budget will be funded.
The above are stated under the headings: “Capital Spending” and “Capital Resources”. Furthermore all statements in the Outlook section of this document contains forward-looking statements.
In addition to other material factors, expectations and assumptions which may be identified in this document and other continuous disclosure documents of the Corporation referenced herein, assumptions have been made in respect of such forward-looking statements and information regarding, among other things: the Corporation will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; anticipated financial performance, business prospects, impact of competition, strategies, the general stability of the economic and political environment in which the Corporation operates; exchange and interest rates; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services and the adequacy of cash flow; debt and ability to obtain financing on acceptable terms to fund its planned expenditures, which are subject to change based on commodity prices; market conditions and future oil and natural gas prices; and potential timing delays. Although Management considers these material factors, expectations and assumptions to be reasonable based on information currently available to it, no assurance can be given that they will prove to be correct.
Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect the Corporation’s operations and financial results are included in reports on file with the Canadian Securities Regulatory Authorities and may be accessed through the SEDAR website (www.sedar.com) or at the Corporation’s website. The forward-looking statements and information contained in this document are expressly qualified by this cautionary statement. The Corporation does not undertake any obligation to publicly update or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Revenue
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | ||||||
| Revenue | 65,396 | 34,964 | 87 | 180,340 | 101,772 | 77 | |||||
The Corporation generated $65.4 million of consolidated revenue in the third quarter of 2017, an increase of 87 percent over the $35.0 million generated in the 2016-quarter. The increase in revenue was primarily the result of higher activity levels as consolidated operating days grew 60 percent to 6,323 days in 2017 from 3,942 days in 2016. In addition, average consolidated day rates, excluding the motor rental division in the US and the Stream division, improved 18 percent to $10,127 in the 2017-quarter from $8,599 in the 2016-quarter. US and international revenue as a percentage of total consolidated revenue was 60 and 7 percent, respectively, for the 2017-quarter as compared to 51 and 12 percent in 2016.
In the 2017-quarter, there were significantly more rigs running per day in both Canada and the US compared to the 2016-quarter. The rig count in Canada and the US was 72 percent and 97 percent higher, respectively. The vast majority of drilling activity continued to be horizontal and directional focused and represented 96 percent of Canadian activity measured by wells drilled (2016 – 96 percent) and 93 percent of US rigs running per day (2016 – 87 percent) (Sources: Daily Oil Bulletin and Baker Hughes).
For the nine-month period ended September 30, 2017, consolidated revenue rose to $180.3 million, an increase of 77 percent from the $101.8 million in the comparable 2016-period. Consolidated operating days in the nine-month period ended September 30, 2017 were 17,756 which is 70 percent greater than the 10,462 days reported in the 2016-period. The average consolidated day rate in the 2017-period, excluding the motor rental division in the US and the Stream division, was $9,878, a 4 percent improvement over the $9,473 realized in the comparable period in 2016.
Operating Costs and Expenses
(Stated in thousands of dollars except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | |||||||
| Direct costs | 59,996 | 40,642 | 48 | 177,577 | 122,906 | 44 | ||||||
| Gross profit (loss) as a percentage of revenue |
8 | % | (16 | %) | 2 | % | (21 | %) | ||||
| Depreciation & amortization (included in direct costs) |
9,988 | 11,851 | (16 | ) | 31,433 | 38,867 | (19 | ) | ||||
| Gross profit as percentage of revenue excluding depreciation & amortization |
24 | % | 18 | % | 19 | % | 17 | % | ||||
Direct costs are comprised of field and shop expenses, and include depreciation and amortization of the Corporation’s equipment. For the three and nine-month periods ended September 30, 2017, direct costs increased to $60.0 million and $177.6 million, respectively, from $40.6 million and $122.9 million in the comparable 2016-periods. The increased direct costs for both 2017-periods were mainly due to higher activity levels, field labour costs and third party rental expenses.
In 2017, the Corporation generated positive gross margins as a result of the greater volume of drilling activity, recovery of day rates and lower depreciation and amortization expenses. For the three and nine-month periods ended September 30, 2017, the gross profit as a percentage of revenue rose to 8 percent and 2 percent, respectively, an improvement over the gross loss as a percentage of revenue of 16 percent and 21 percent in the comparable 2016-periods.
The reduction in the depreciation and amortization expense for the three and nine-month periods ended September 30, 2017 was mainly the result of PHX Energy’s lower levels of capital spending in the 2016 and 2017-years. Excluding depreciation and amortization, gross profit as a percentage of revenue improved to 24 percent and 19 percent for the three and nine-month periods ended September 30, 2017, up from 18 percent and 17 percent in the respective 2016-periods. The higher 2017 margins were primarily the result of increased drilling activity and day rates.
(Stated in thousands of dollars except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | |||||||||
| Selling, general & administrative (“SG&A”) costs | 7,759 | 8,155 | (5 | ) | 22,744 | 21,714 | 5 | |||||||
| Equity-settled share-based payments (included in SG&A costs) |
701 | 480 | 46 | 2,219 | 1,377 | 61 | ||||||||
| Cash-settled share-based payments (recoveries) (included in SG&A costs) |
802 | 1,561 | (49 | ) | 775 | 2,509 | (69 | ) | ||||||
| Onerous contracts lease payment | (95 | ) | – | n.m. | (272 | ) | – | n.m. | ||||||
| SG&A costs excluding equity and cash-settled share- based payments and provision for onerous contracts as a percentage of revenue |
10 | % | 17 | % | 11 | % | 18 | % | ||||||
n.m. – not meaningful
Excluding the impact of equity and cash-settled share-based payments and the provision for onerous contracts, SG&A costs for both the three and nine-month periods ended September 30, 2017 increased in accordance with the higher activity levels as compared to the 2016-periods. Although activity in the third quarter of 2017 increased by 60 percent over the comparable 2016-quarter, SG&A costs, excluding those items listed above, increased by only 4 percent. The marginal 2017 increase was the result of effective cost control measures implemented since the onset of the downturn.
For the three and nine-month periods ended September 30, 2017, excluding equity and cash-settled share-based payments and the provision for onerous contracts, SG&A costs as a percentage of consolidated revenue improved to 10 percent and 11 percent, respectively, over 17 percent and 18 percent in the comparable 2016-periods. The improved percentages in both 2017-periods were mainly attributable to the increased volume of drilling activity and the stabilization of day rates.
Equity-settled share-based payments relate to the amortization of the fair values of issued options of the Corporation using the Black-Scholes model. In the three and nine-month periods ended September 30, 2017, equity-settled share-based payments increased by 46 percent and 61 percent, respectively over the corresponding 2016-periods. The rise in equity-settled compensation expense in both current year periods was primarily the result of higher fair values on options granted in the first quarter of 2017 as compared to 2016 and new options granted in the third quarter of 2017.
Cash-settled share-based retention awards, which are included in SG&A costs, are measured at fair value. The Corporation recognized cash-settled compensation expenses of $0.8 million in both the three and nine-month periods ended September 30, 2017 as compared to $1.6 million and $2.5 million in the respective 2016-periods. The lower compensation expense in 2017 was primarily the result of fluctuations in the Corporation’s share price in both periods.
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | ||||
| Research & development expense | 287 | 582 | (51) | 1,658 | 1,332 | 24 | |||
Research and development (“R&D”) expenditures during the three and nine-month periods ended September 30, 2017 were $0.3 million (2016 – $0.6 million) and $1.7 million (2016 – $1.3 million), respectively. The 2017-periods contain the receipt of a scientific research and experimental development (“SR&ED”) credit, which reduced the research & development expense by $0.4 million.
Excluding the impact of SR&ED credits, R&D expenditures were higher in both 2017-periods, which is mainly the result of a more R&D personnel in the current year. The R&D department remains focused on the development of new technology and initiatives to further enhance and expand PHX Energy’s services.
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | |||
| Finance expense | 482 | 352 | 37 | 1,495 | 1,450 | 3 | ||
Finance expenses relate to interest charges on the Corporation’s long-term and short-term bank facilities. For the three and nine-months periods ended September 30, 2017, the finance expense increased over the comparable 2016-periods. The increase in finance charges in both 2017-periods was primarily due to higher rates on borrowings, additional financing charges from the amendment to the credit facility completed in the fourth quarter of 2016 and accretion charges associated with the Corporation’s provision for onerous contracts.
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||
| Loss (Gain) on disposition of drilling equipment | (3,548 | ) | 62 | (3,789 | ) | (717 | ) | |||||
| Foreign exchange losses (gains) | 119 | 59 | 374 | (167 | ) | |||||||
| Provision for (Recovery of) bad debts | 123 | 262 | 375 | 196 | ||||||||
| Other Expenses (Income) | (3,306 | ) | 383 | (3,040 | ) | (688 | ) | |||||
For the three and nine-month periods ended September 30, 2017, the Corporation incurred other income of $3.3 million (2016 – expense of $0.4 million) and $3.0 million (2016 – $0.7 million), respectively, which was mainly the result of gains on the disposition of drilling equipment. Gains typically result from insurance programs undertaken whereby proceeds for the lost equipment are at current replacement values, which are higher than the respective equipment’s book value. Losses typically result from any asset retirements that were made before the end of the equipment’s useful life and self-insured downhole equipment losses. In the 2017-periods, the gain on disposition of drilling equipment resulted primarily from insured lost equipment.
For the three and nine-month periods ended September 30, 2017, the Corporation incurred foreign exchange losses of $0.1 million (2016 – $0.1 million) and $0.4 million (2016 – $0.2 million gain), respectively. These losses resulted mainly from the settlement of Canadian-denominated intercompany payables in the Corporation’s Russian operations and the revaluation of Canadian-denominated intercompany payables in the US.
During the three and nine-month periods ended September 30, 2017, the Corporation recognized provisions for bad debts of $0.1 million (2016 – $0.3 million) and $0.4 million (2016 – $0.2 million), respectively. Provisions for bad debt in the 2017-quarter relate mainly to accounts receivable in the Corporation’s US segment.
(Stated in thousands of dollars, except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||
| Provision for (Recovery of) income taxes | 1,025 | (4,471 | ) | (1,691 | ) | (13,499 | ) | ||
| Effective tax rates | n.m. | 30 | % | 8 | % | 30 | % | ||
n.m. – not meaningful
For the three-month period ended September 30, 2017, the Corporation recognized a provision for income taxes of $1.0 million (2016 – recovery of $4.5 million) primarily from taxable income generated in the Corporation’s US entity. For the nine-month period ended September 30, 2017, a recovery of $1.7 million was recorded as compared to $13.5 million in the corresponding 2016-period. The expected combined Canadian federal and provincial tax rate for 2017 is 27 percent. For the nine-month period ended September 30, 2017, the effective tax rate was lower than the expected rate as a result of the effect of tax rates in foreign jurisdictions.
Segmented Information
The Corporation reports three operating segments on a geographical basis throughout the Canadian provinces of Alberta, Saskatchewan, British Columbia, and Manitoba; throughout the Gulf Coast, Northeast and Rocky Mountain regions of the US; and internationally, in Russia and Albania.
Canada
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | |||||||||
| Revenue | 21,731 | 12,963 | 68 | 64,623 | 34,415 | 88 | ||||||||
| Reportable segment loss before tax | (1,363 | ) | (3,962 | ) | (66 | ) | (5,842 | ) | (14,522 | ) | (60 | ) | ||
For the three-month period ended September 30, 2017, Canadian revenue increased by 68 percent to $21.7 million from $13.0 million in the corresponding 2016-period. The increase was mainly driven by the segment recording 60 percent more operating days in the 2017-quarter, 2,795 days, compared to the 2016-quarter, 1,751 days. In comparison, the industry’s horizontal and directional drilling activity, as measured by drilling days, increased by 89 percent to 18,127 days in the 2017-quarter from 9,577 days in the equivalent 2016-quarter (Source: Daily Oil Bulletin). The Corporation’s average day rate rose from $7,096 in the 2016-quarter to $7,424 in 2017, excluding Stream revenue of $1.0 million (2016 – $0.5 million).
During the third quarter of 2017, oil drilling, as measured by drilling days, represented approximately 70 percent of PHX Energy’s Canadian activity and the Corporation remained active in the Montney, Wilrich, Bakken, Shaunavon, Duvernay, Cardium and Viking areas.
PHX Energy’s Canadian revenue for the nine-month period of 2017, increased by 88 percent to $64.6 million from $34.4 million in the comparable 2016-period. The Canadian segment recorded 8,498 operating days in 2017, a 95 percent increase over the 4,365 days in 2016. In comparison, for the nine-month period ended September 30, 2017, there were 50,950 horizontal and directional drilling days realized in the Canadian industry, which is more than double the 24,070 days realized in the equivalent 2016-period (Sources: Daily Oil Bulletin). As a result of market conditions in the first half of 2017 and an increased proportion of wells requiring fewer rig site personnel, average day rates, excluding Stream revenue, for the first nine-months of 2017 declined slightly to $7,250 from $7,643 in the comparable 2016-period.
The Canadian operations’ reportable segment loss before tax for the three and nine-month periods ended September 30, 2017 was $1.4 million (2016 – $4.0 million) and $5.8 million (2016 – $14.5 million), respectively. The reduced losses in both 2017-periods were reflective of the greater volume of drilling activity.
Stream Services
Included in the Canadian segment’s revenue for the three and nine-month periods ended September 30, 2017 is Stream revenue of $1.0 million (2016 – $0.5 million) and $3.0 million (2016 – $1.1 million), respectively. The increase in revenue for both 2017-periods was the result of higher activity. For the three and nine-month periods ended September 30, 2017, the division recorded 1,338 operating days (2016 – 772 days) and 3,930 operating days (2016 – 1,657 days), respectively. Along with the growth in activity, average day rates rose by 6 percent to $737 in the third quarter of 2017 from $698 in the 2016-quarter.
For the three and nine-month periods ended September 30, 2017, the Stream division incurred reportable losses before tax of $1.1 million (2016 – $1.5 million) and $2.9 million (2016 – $5.0 million). The Stream division’s losses in both 2017-periods pertain mostly to depreciation expenses of $0.6 million and $1.8 million, respectively, as well as the costs associated with the expansion of the division.
United States
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | ||||||||
| Revenue | 39,339 | 17,752 | 122 | 101,360 | 56,872 | 78 | |||||||
| Reportable segment profit (loss) before tax | 712 | (8,108 | ) | n.m. | (9,469 | ) | (22,715 | ) | (58 | ) | |||
n.m. – not meaningful
Revenue from PHX Energy’s US operations in the third quarter of 2017 increased to $39.3 million from $17.8 million in the 2016-quarter as a result of higher activity and day rates. In the third quarter of 2017, the average number of horizontal and directional rigs running per day grew to 876 rigs in 2017, which is more than double the 418 rigs running in the 2016-quarter (Source: Baker Hughes). Activity levels in the US segment improved as operating days rose 100 percent from 1,483 days in the 2016-quarter to 2,969 days in 2017. Average day rates in the US, excluding motor rentals, improved 13 percent in the third quarter of 2017 rising to $13,123 versus $11,614 in the comparable 2016-period.
In the third quarter of 2017, horizontal and directional drilling continued to represent a large majority of the industry rig count, averaging 93 percent of the rigs running on a daily basis. Oil well drilling, as measured by wells drilled and excluding the motor rental and gyro surveying divisions, increased to 92 percent of PHX Energy’s US activity in the 2017-quarter, as a large portion of the industry’s drilling activity remained concentrated in Texas, specifically the Permian basin. During the third quarter of 2017, Phoenix USA remained active in the Permian, Mississippian/Woodford, Marcellus, Utica, Niobrara and Bakken basins.
For the nine-month period ended September 30, 2017, US revenue was $101.4 million, an increase of 78 percent over the $56.9 million recognized in the comparable 2016-period. During the 2017 nine-month period, US operating days increased 70 percent from 4,321 days in 2016 to 7,362. In comparison, as measured by the average number of horizontal and directional rigs running on a daily basis, US industry activity rose by 86 percent in the 2017 nine-month period to 789 rigs from 424 rigs in the comparable 2016-period (Source: Baker Hughes). For the nine-month period ended September 30, 2017, the US segment achieved average day rates of $13,504, an increase of 6 percent over the $12,788 in the 2016-period.
As a result of the increased activity level and day rates, the US segment reported improved before tax margins for both the three and nine-month periods ended September 30, 2017 over the comparable 2016-periods.
International
(Stated in thousands of dollars, except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2017 | 2016 | % Change | 2017 | 2016 | % Change | |||||||
| Revenue | 4,326 | 4,249 | 2 | 14,357 | 10,485 | 37 | ||||||
| Reportable segment profit (loss) before tax | (69 | ) | 267 | n.m. | (784 | ) | (1,466 | ) | (47 | ) | ||
n.m. – not meaningful
For the three-month period ended September 30, 2017, the Corporation’s international segment generated revenue of $4.3 million, a slight increase from the $4.2 million earned in the comparable 2016-period. The growth in 2017 revenue was largely from the continued expansion of the Russian measurement while drilling (“MWD”) rental activity and strengthening of the Russian ruble. In the third quarter of 2017, the Corporation recorded 560 international operating days, excluding the MWD rental activity, a decrease of 21 percent from the 708 days in the 2016-quarter. Albania was only active for a portion of the 2017-quarter where as in the comparable 2016-period the Albanian operations were idle and all activity was generated in Russia.
During the third quarter of 2017, the international segment had a reportable segment loss before tax of $0.1 million, as compared to a profit of $0.3 million in 2016. The lower margin in the 2017-quarter was primarily the result of increased Russian personnel costs.
For the nine-month period ended September 30, 2017, international revenue grew by 37 percent to $14.4 million from $10.5 million in the comparable 2016-period. International operating days rose by 7 percent to 1,897 days in the 2017 nine-month period, as compared to 1,776 days in 2016. The international segment reported losses before tax for the nine-month period ended September 30, 2017 of $0.8 million, a 47 percent improvement from the $1.5 million loss in the 2016-period. The improved 2017 revenue and segment loss were primarily the result of the expanded Russian MWD rental activity and higher total operating days as drilling in Albania recommenced in the fourth quarter of 2016 and was active until July 2017.
Investing Activities
Net cash used in investing activities for the three-month period ended September 30, 2017 was $3.8 million (2016 – $2.0 million). During the third quarter of 2017, the Corporation acquired $8.9 million of drilling and other equipment (2016 – $2.4 million) and received proceeds of $4.9 million from the disposition of drilling equipment, primarily related to involuntary disposal of drilling equipment in well bores (2016 – $0.4 million). The quarterly 2017 expenditures included:
- $6.4 million in MWD systems and spare components;
- $1.9 million in downhole performance drilling motors;
- $0.5 million in EDR equipment and spare components; and
- $0.1 million in software and machinery and equipment.
The capital expenditure program undertaken in the period was financed generally from funds from operations and drawdowns on credit facilities.
During the 2017-quarter, the Corporation spent $0.9 million in intangible assets, consisting of license payments and development costs.
The change in non-cash working capital balances of $1.0 million (source of cash) for the three-month period ended September 30, 2017, relates to the net change in the Corporation’s trade payables that are associated with the acquisition of capital assets. This compares to $1.2 million for the three-month period ended September 30, 2016.
Financing Activities
The Corporation reported cash flows from financing activities of $14.8 million for the three-month period ended September 30, 2017 as compared to $2.5 million in the comparable 2016-period. The Corporation drew net proceeds of $14.9 million on its operating and syndicated facilities during the third quarter of 2017.
Capital Resources
As of September 30, 2017, the Corporation had $14.0 million drawn on its syndicated facility, $5.1 million drawn on its operating facility, and USD $1.5 million drawn on its US operating facility. As at September 30, 2017, the Corporation had $1.6 million in cash-on-hand and $37.8 million available to be drawn from its credit facilities. The credit facilities are secured by substantially all of the Corporation’s assets.
As at September 30, 2017, the Corporation was in compliance with all of its financial covenants.
Cash Requirements for Capital Expenditures
Historically, the Corporation has financed its capital expenditures and acquisitions through cash flows from operating activities, debt and equity. The 2017 capital budget remains at $25.0 million. These planned expenditures are expected to be financed from a combination of one or more of the following: cash flow from operations, the Corporation’s unused credit facilities or equity, if necessary. However, if a sustained period of market uncertainty and financial market volatility persists in 2017, the Corporation’s activity levels, cash flows and access to credit may be negatively impacted, and the expenditure level would be reduced accordingly. Conversely, if future growth opportunities present themselves, the Corporation would look at expanding this planned capital expenditure amount.
Outlook
The third quarter of 2017 produced many positive results including, a strong increase in consolidated activity levels, revenue and profitability. The Corporation achieved its highest profitability as measured by adjusted EBITDA as a percentage of revenue since the early stages of the downturn in the fourth quarter of 2014.
During the third quarter, the Corporation’s Canadian activity levels and revenue increased as compared to the same quarter in 2016. This level of activity is anticipated to carry through to the first quarter of 2018, with the exception of the typical slowdown at year-end. PHX Energy has maintained its healthy market share in Canada and will remain focused on leveraging our strong marketing relationships, superior operational performance and differentiating technology to retain this position.
The Corporation achieved successful strides in its strategy to grow its presence in the US market. In the quarter, the US segment achieved significant gains in revenue and operating days that resulted in enhanced profitability. The active rig count in the US has slightly leveled off in the fourth quarter, however, PHX Energy believes its US operations will continue to increase market share. The rollout of additional Velocity systems in the upcoming quarters, as well as other new technologies, will help propel this growth. The US marketing and operations team continues to thrive, providing clients with exceptional service and operational performance. The US market remains the greatest opportunity for growth and PHX Energy is diligently focused on deploying differentiating technology to the most active basins.
Activity in PHX Energy’s international operations remained steady in the third quarter. The Russia division continues to focus on diversifying its client base and growing its MWD rental activity. The Corporation anticipates Russia will present growth opportunities and achieve higher activity levels in the fourth quarter and into 2018. During the third quarter, the Albania operations became idle due to the Corporation’s client in the region suspending operations. Phoenix Albania will retain its ability to recommence operations with little notification required.
During the quarter, Stream made its first steps in entering the US market deploying its DataStream EDR platform to one rig. It is anticipated that further opportunities and growth will evolve in this highly attractive market for EDR services. Activity levels in Canada increased from the prior year’s quarter, however, PHX Energy is focused on gaining greater volumes of activity in future quarters.
Technology Update
As the industry is demanding greater efficiency, many service providers, including PHX Energy, are developing technologies focused on remote operations and automating services. Fast, reliable and robust downhole drilling technology is an integral component of any successful drilling operation, especially automated rig sites and remote operations. In this regard, PHX Energy’s technology strategy has equipped the Corporation with significant competitive advantages.
Operators continue to benefit from the significant advantages Velocity offers and PHX Energy is able to charge a premium for this differentiating technology. Demand continues to outweigh supply and the Corporation is manufacturing additional systems for deployment in the upcoming quarters. PHX Energy continues to develop new features and enhancements that will further set Velocity apart from other MWD platforms in the market.
Our newly developed 7.25” Atlas drilling motor continues to gain momentum and is building a reputation for its superior drilling performance. This motor is designed to exceed the capabilities of higher capacity drilling rigs allowing for faster drilling and maximizing the operating parameters.
In the third quarter, PHX Energy added another unique and differentiating technology to its product line, as the Corporation successfully commercialized its At-Bit platform. PHX Energy is now one of the few providers to offer this service, and this is a major accomplishment for the Corporation. The At-Bit platform offers greater precision by capturing advanced data measurements from directly behind the drill bit opposed to further back in the drill string. Based on high demand for this product, the Corporation is building its fleet accordingly.
As the industry is recovering, PHX Energy continues to leverage its technology development to create growth opportunities as well as to secure its position as a key player in delivering greater wellsite efficiencies to its clients.
Michael Buker
President
November 2, 2017
Non-GAAP Measures
1) Adjusted EBITDA
Adjusted EBITDA, defined as earnings before finance expense, income taxes, depreciation and amortization, impairment losses on goodwill and intangible assets, provisions for the settlement of litigations, equity and cash-settled share-based payments, severance costs and other non-cash charges, is not a financial measure that is recognized under GAAP. However, Management believes that adjusted EBITDA provides supplemental information to net earnings that is useful in evaluating the results of the Corporation’s principal business activities before considering other non-recurring charges, how it was financed and how it was taxed in various countries. Investors should be cautioned, however, that adjusted EBITDA should not be construed as an alternative measure to net earnings determined in accordance with GAAP. PHX Energy’s method of calculating adjusted EBITDA may differ from that of other organizations and, accordingly, its adjusted EBITDA may not be comparable to that of other companies.
The following is a reconciliation of net earnings to adjusted EBITDA:
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||
| Net loss | (846 | ) | (10,679 | ) | (18,401 | ) | (31,442 | ) | ||
| Add (deduct): | ||||||||||
| Depreciation and amortization | 9,988 | 11,851 | 31,433 | 38,867 | ||||||
| Provision for (Recovery of) income taxes | 1,025 | (4,471 | ) | (1,691 | ) | (13,499 | ) | |||
| Finance expense | 482 | 352 | 1,495 | 1,450 | ||||||
| Equity-settled share-based payments | 701 | 480 | 2,219 | 1,377 | ||||||
| Cash-settled share-based payments (recoveries) |
802 | 1,561 | 775 | 2,509 | ||||||
| Severance costs | – | 374 | 785 | 1,703 | ||||||
| Provision for inventory | 300 | 300 | 900 | 900 | ||||||
| Provision for onerous contracts | (95 | ) | – | (272 | ) | – | ||||
| Adjusted EBITDA as reported | 12,357 | (232 | ) | 17,243 | 1,865 | |||||
Adjusted EBITDA per share – diluted is calculated using the treasury stock method whereby deemed proceeds on the exercise of the share options are used to reacquire common shares at an average share price. The calculation of adjusted EBITDA per share on a dilutive basis does not include anti-dilutive options.
2) Funds from Operations
Funds from operations is defined as cash flows generated from operating activities before changes in non-cash working capital, interest paid, and income taxes paid. This is not a measure recognized under GAAP. Management uses funds from operations as an indication of the Corporation’s ability to generate funds from its operations before considering changes in working capital balances and interest and taxes paid. Investors should be cautioned, however, that this financial measure should not be construed as an alternative measure to cash flows from operating activities determined in accordance with GAAP. PHX Energy’s method of calculating funds from operations may differ from that of other organizations and, accordingly, it may not be comparable to that of other companies.
The following is a reconciliation of cash flows from operating activities to funds from operations:
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||
| Cash flows from (used in) operating activities | (13,684 | ) | (100 | ) | (9,910 | ) | 4,732 | |||
| Add (deduct): | ||||||||||
| Changes in non-cash working capital | 25,968 | (2,038 | ) | 25,466 | (3,261 | ) | ||||
| Interest paid | 244 | 221 | 740 | 982 | ||||||
| Income taxes received | (4,092 | ) | 23 | (3,763 | ) | (3,955 | ) | |||
| Funds from operations | 8,436 | (1,894 | ) | 12,533 | (1,502 | ) | ||||
Funds from operations per share – diluted is calculated using the treasury stock method whereby deemed proceeds on the exercise of the share options are used to reacquire common shares at an average share price. The calculation of funds from operations per share on a dilutive basis does not include anti-dilutive options.
3) Working Capital
Working capital is defined as the Corporation’s current assets less its current liabilities and is used to assess the Corporation’s short-term liquidity.
About PHX Energy Services Corp.
The Corporation, through its directional drilling subsidiary entities, provides horizontal and directional drilling technology and services to oil and natural gas producing companies in Canada, the US, Russia and Albania. PHX Energy also provides electronic drilling recorder (“EDR”) technology and services.
PHX Energy’s Canadian directional drilling operations are conducted through Phoenix Technology Services LP. The Corporation maintains its corporate head office, research and development, Canadian sales, service and operational centres in Calgary, Alberta. In addition, PHX Energy has a facility in Estevan, Saskatchewan. PHX Energy’s US operations, conducted through the Corporation’s wholly-owned subsidiary, Phoenix Technology Services USA Inc. (“Phoenix USA”), is headquartered in Houston, Texas. Phoenix USA has sales and service facilities in Houston, Texas; Denver, Colorado; Casper, Wyoming; Midland, Texas; Bellaire, Ohio; and Oklahoma City, Oklahoma. Internationally, PHX Energy has sales offices and service facilities in Albania and Russia, and administrative offices in Nicosia, Cyprus; Dublin, Ireland; and Luxembourg City, Luxembourg.
PHX Energy markets its EDR technology and services in Canada through its division, Stream Services, which has an office and operations center in Calgary, Alberta. EDR technology is marketed worldwide outside Canada through its wholly-owned subsidiary Stream Services International Inc.
For further information please contact:
John Hooks, CEO; Michael Buker, President; or Cameron Ritchie, Senior Vice President Finance and CFO
PHX Energy Services Corp.
Suite 1400, 250 2nd Street SW
Calgary, Alberta T2P 0C1
Tel: 403-543-4466 Fax: 403-543-4485 www.phxtech.com
Consolidated Statements of Financial Position
(unaudited)
| September 30, 2017 | December 31, 2016 | ||||||||
| ASSETS | |||||||||
| Current assets: | |||||||||
| Cash and cash equivalents | $ | 1,626,243 | $ | 7,007,293 | |||||
| Trade and other receivables | 74,746,884 | 41,552,796 | |||||||
| Inventories | 23,805,686 | 24,988,472 | |||||||
| Prepaid expenses | 2,780,324 | 2,613,716 | |||||||
| Current tax assets | 980,873 | 5,293,489 | |||||||
| Total current assets | 103,940,010 | 81,455,766 | |||||||
| Non-current assets: | |||||||||
| Drilling and other equipment | 100,875,975 | 121,172,229 | |||||||
| Goodwill | 8,876,351 | 8,876,351 | |||||||
| Intangible assets | 26,092,180 | 26,302,314 | |||||||
| Deferred tax assets | 13,441,069 | 10,687,684 | |||||||
| Total non-current assets | 149,285,575 | 167,038,578 | |||||||
| Total assets | $ | 253,225,585 | $ | 248,494,344 | |||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||
| Current liabilities: | |||||||||
| Operating facility | $ | 5,146,790 | $ | 6,031,547 | |||||
| Trade and other payables | 42,475,012 | 31,194,630 | |||||||
| Total current liabilities | 47,621,802 | 37,226,177 | |||||||
| Non-current liabilities: | |||||||||
| Loans and borrowings | 15,872,000 | 29,014,050 | |||||||
| Provision for onerous contracts | 2,143,000 | 2,300,000 | |||||||
| Deferred income | 1,466,672 | 1,566,671 | |||||||
| Total non-current liabilities | 19,481,672 | 32,880,721 | |||||||
| Equity: | |||||||||
| Share capital | 267,231,147 | 237,539,242 | |||||||
| Contributed surplus | 8,934,583 | 6,817,458 | |||||||
| Retained earnings | (101,311,913 | ) | (82,910,425 | ) | |||||
| Accumulated other comprehensive income | 11,268,294 | 16,941,171 | |||||||
| Total equity | 186,122,111 | 178,387,446 | |||||||
| Total liabilities and equity | $ | 253,225,585 | $ | 248,494,344 | |||||
Consolidated Statements of Comprehensive Loss
(unaudited)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Revenue | $ | 65,396,316 | $ | 34,964,130 | $ | 180,340,476 | $ | 101,772,027 | |||||||
| Direct costs | 59,995,834 | 40,642,117 | 177,576,571 | 122,905,878 | |||||||||||
| Gross profit (loss) | 5,400,482 | (5,677,987 | ) | 2,763,905 | (21,133,851 | ) | |||||||||
| Expenses: | |||||||||||||||
| Selling, general and administrative expenses | 7,758,571 | 8,155,063 | 22,743,776 | 21,713,636 | |||||||||||
| Research and development expenses | 286,809 | 581,893 | 1,657,872 | 1,331,867 | |||||||||||
| Finance expense | 482,056 | 351,525 | 1,494,825 | 1,450,339 | |||||||||||
| Other expenses (income) | (3,305,599 | ) | 383,116 | (3,040,009 | ) | (687,981 | ) | ||||||||
| 5,221,837 | 9,471,597 | 22,856,464 | 23,807,861 | ||||||||||||
| Earnings (Loss) before income taxes | 178,645 | (15,149,584 | ) | (20,092,559 | ) | (44,941,712 | ) | ||||||||
| Provision for (Recovery of) income taxes | |||||||||||||||
| Current | (67,491 | ) | (19,295 | ) | 230,911 | (5,303,499 | ) | ||||||||
| Deferred | 1,092,217 | (4,451,466 | ) | (1,921,982 | ) | (8,195,880 | ) | ||||||||
| 1,024,726 | (4,470,761 | ) | (1,691,071 | ) | (13,499,379 | ) | |||||||||
| Net loss | (846,081 | ) | (10,678,823 | ) | (18,401,488 | ) | (31,442,333 | ) | |||||||
| Other comprehensive income (loss) | |||||||||||||||
| Foreign currency translation | (3,340,547 | ) | 1,936,330 | (5,672,877 | ) | (4,914,785 | ) | ||||||||
| Total comprehensive loss for the period | $ | (4,186,628 | ) | $ | (8,742,493 | ) | $ | (24,074,365 | ) | $ | (36,357,118 | ) | |||
| Loss per share – basic | $ | (0.01 | ) | $ | (0.21 | ) | $ | (0.32 | ) | $ | (0.70 | ) | |||
| Loss per share – diluted | $ | (0.01 | ) | $ | (0.21 | ) | $ | (0.32 | ) | $ | (0.70 | ) | |||
Consolidated Statements of Cash Flows
(unaudited)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||
| Cash flows from operating activities: | |||||||||||||
| Net loss | $ | (846,081 | ) | $ | (10,678,823 | ) | $ | (18,401,488 | ) | $ | (31,442,333 | ) | |
| Adjustments for: | |||||||||||||
| Depreciation and amortization | 9,988,025 | 11,851,226 | 31,433,424 | 38,866,653 | |||||||||
| Provision for (Recovery of) income taxes | 1,024,726 | (4,470,761 | ) | (1,691,071 | ) | (13,499,379 | ) | ||||||
| Unrealized foreign exchange loss (gain) | 339,407 | (17,662 | ) | 363,840 | 1,467,103 | ||||||||
| Loss (Gain) on disposition of drilling equipment | (3,547,501 | ) | 61,872 | (3,788,667 | ) | (717,121 | ) | ||||||
| Equity-settled share-based payments | 700,803 | 479,780 | 2,218,672 | 1,377,014 | |||||||||
| Finance expense | 482,056 | 351,525 | 1,494,825 | 1,450,339 | |||||||||
| Amortization of deferred income | (33,333 | ) | (33,333 | ) | (99,999 | ) | (99,999 | ) | |||||
| Provision for bad debts | 123,360 | 261,970 | 375,260 | 196,278 | |||||||||
| Other non-cash charges | 205,000 | 300,000 | 628,000 | 899,899 | |||||||||
| Interest paid | (244,272 | ) | (221,159 | ) | (739,588 | ) | (981,588 | ) | |||||
| Income taxes received (paid) | 4,092,277 | (22,868 | ) | 3,763,191 | 3,954,506 | ||||||||
| Change in non-cash working capital | (25,968,400 | ) | 2,038,048 | (25,466,029 | ) | 3,261,005 | |||||||
| Net cash from (used in) operating activities | (13,683,933 | ) | (100,185 | ) | (9,909,630 | ) | 4,732,377 | ||||||
| Cash flows from investing activities: | |||||||||||||
| Proceeds on disposition of drilling equipment | 4,929,341 | 359,365 | 7,960,388 | 3,214,891 | |||||||||
| Acquisition of drilling and other equipment | (8,900,250 | ) | (2,364,577 | ) | (17,396,837 | ) | (5,256,107 | ) | |||||
| Acquisition of intangible assets | (861,306 | ) | (1,255,709 | ) | (1,492,583 | ) | (2,188,061 | ) | |||||
| Change in non-cash working capital | 1,036,639 | 1,235,277 | 363,187 | 1,401,157 | |||||||||
| Net cash used in investing activities | (3,795,576 | ) | (2,025,644 | ) | (10,565,845 | ) | (2,828,120 | ) | |||||
| Cash flows from financing activities: | |||||||||||||
| Proceeds from issuance of share capital | – | 22,230 | 29,154,582 | 23,243,889 | |||||||||
| Dividends paid to shareholders | – | – | – | (415,670 | ) | ||||||||
| Proceeds from (Repayment of) loans and borrowings |
10,872,000 | (2,095,010 | ) | (13,142,050 | ) | (40,018,640 | ) | ||||||
| Repurchase of shares under the NCIB | (33,350 | ) | – | (33,350 | ) | – | |||||||
| Proceeds from (Repayment of) operating facility | 3,988,889 | 4,574,849 | (884,757 | ) | 8,869,361 | ||||||||
| Net cash from (used in) financing activities | 14,827,539 | 2,502,069 | 15,094,425 | (8,321,060 | ) | ||||||||
| Net increase (decrease) in cash and cash equivalents |
(2,651,970 | ) | 376,240 | (5,381,050 | ) | (6,416,803 | ) | ||||||
| Cash and cash equivalents, beginning of period | 4,278,213 | 2,214,765 | 7,007,293 | 9,007,808 | |||||||||
| Cash and cash equivalents, end of period | $ | 1,626,243 | $ | 2,591,005 | $ | 1,626,243 | $ | 2,591,005 | |||||