CALGARY, ALBERTA–(Marketwired – Nov. 9, 2016) – PHX Energy Services Corp. (TSX:PHX)
Financial Results
During the third quarter of 2016, the directional drilling market continued to be highly competitive which caused average day rates and profitability margins to decline to some of the lowest levels in the Corporation’s history. The intense competition was the result of the further deterioration of industry activity over the prior year as weak commodity prices prevailed in the third quarter. For the three-month period ended September 30, 2016, PHX Energy generated consolidated revenue of $35.0 million, a 49 percent decrease from the $68.2 million generated in the comparable 2015-period. The Corporation realized a net loss of $10.7 million in the 2016-quarter compared to a net loss of $24.5 million in the 2015-quarter, which included a pre-tax impairment charge of $13.8 million related to Stream Service’s (“Stream”) goodwill and intangible assets. The Corporation’s adjusted EBITDA(1) declined to negative $0.2 million in the third quarter of 2016 where as in the prior year’s quarter it was positive $4.2 million. Included in the adjusted EBITDA for the third quarter of 2016, is Stream’s adjusted EBITDA of negative $0.8 million. Stream’s adjusted EBITDA was impacted by incremental costs associated with the commercialization of its new product line and wet weather causing delays in the deployment of systems.
During the third quarter of 2016, PHX Energy’s Electronic Drilling Recorder (“EDR”) division, Stream, commercially released its new DataStream EDR product line (“DataStream”). The launch of DataStream will allow the Corporation to successfully diversify its business with a competitive service offering in an attractive sector of the oil and gas services market where there are only a few providers. As at September 30, 2016, Stream had an operating capacity of 15 rigs in western Canada. Management believes in upcoming quarters demand for DataStream will outpace supply, and as a result, PHX Energy intends to double Stream’s job capacity by early 2017. It is anticipated that the division’s losses will decrease as the revenue stream grows and positive margins will be achieved in future quarters. The Corporation will continue to leverage existing resources to support the expansion of this service offering to achieve greater margins.
As at September 30, 2016, PHX Energy had long-term debt of $20.0 million and working capital of $38.3 million.
Capital Spending
The Corporation remained cautious with its capital spending during the third quarter of 2016. For the three-month period ended September 30, 2016, $2.4 million in capital expenditures were incurred, which is consistent with the amount spent in the comparable 2015-period. At the end of September 2016, an additional $3.5 million of equipment is on order, $3.2 million of which is expected to be received within the fourth quarter.
(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, | |||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||
| Operating Results | (unaudited) | (unaudited) | (unaudited) | (unaudited) | ||||||||
| Revenue | 34,964 | 68,227 | (49 | ) | 101,772 | 230,642 | (56 | ) | ||||
| Net loss | (10,679 | ) | (24,515 | ) | (56 | ) | (31,442 | ) | (38,707 | ) | (19 | ) |
| Loss per share – diluted | (0.21 | ) | (0.59 | ) | (64 | ) | (0.70 | ) | (1.03 | ) | (32 | ) |
| Adjusted EBITDA (1) | (232 | ) | 4,229 | n.m. | 1,865 | 13,968 | (87 | ) | ||||
| Adjusted EBITDA per share – diluted (1) | – | 0.10 | n.m. | 0.04 | 0.37 | (89 | ) | |||||
| Cash Flow | ||||||||||||
| Cash flows from operating activities | (100 | ) | 10,780 | n.m. | 4,732 | 42,950 | (89 | ) | ||||
| Funds from operations (1) | (1,894 | ) | 677 | n.m. | (1,502 | ) | 4,317 | n.m. | ||||
| Funds from operations per share – diluted (1) | (0.04 | ) | 0.02 | n.m. | (0.03 | ) | 0.12 | n.m. | ||||
| Dividends paid | – | 2,181 | (100 | ) | 416 | 12,681 | (97 | ) | ||||
| Dividends per share (2) | – | 0.05 | (100 | ) | 0.01 | 0.35 | (97 | ) | ||||
| Capital expenditures | 2,365 | 2,338 | 1 | 5,256 | 17,156 | (69 | ) | |||||
| Financial Position (unaudited) | Sep 30, ’16 | Dec 31, ’15 | ||||||||||
| Working capital | 38,322 | 61,041 | (37 | ) | ||||||||
| Long-term debt | 20,000 | 60,000 | (67 | ) | ||||||||
| Shareholders’ equity | 189,583 | 200,938 | (6 | ) | ||||||||
| Common shares outstanding | 50,705,722 | 41,567,023 | 22 | |||||||||
| 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 document 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, and debt to covenant EBITDA ratio. 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, projections related to Stream’s future activity levels, profitability and financial performance, delivery of capital expenditure items, and the projected capital expenditures budget and how this budget will be funded.
The above are stated under the headings: “Financial Results”, “Segmented Information” 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 MD&A 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, | |||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||
| Revenue | 34,964 | 68,227 | (49 | ) | 101,772 | 230,642 | (56 | ) |
As weak commodity prices prevailed during the third quarter of 2016, slower activity in all of the Corporation’s operating segments persisted and the Corporation saw the lowest day rates in its history as pricing pressures continued. For the three-month period ended September 30, the Corporation realized a 49 percent reduction in consolidated revenue from $68.2 million in 2015 to $35.0 million in 2016. US and international revenue as a percentage of total consolidated revenue were 51 and 12 percent, respectively, for the 2016-quarter as compared to 62 and 9 percent in 2015. Consolidated operating days decreased by 27 percent from 5,387 days in the third quarter of 2015 to 3,942 days in the 2016-quarter. Average consolidated day rates for the three-month period ended September 30, 2016, excluding the motor rental division in the US and the Stream division, declined by 30 percent to $8,599 from $12,269 in the third quarter of 2015.
In the 2016-quarter North American rig counts remained approximately 39 percent lower than the rig count experienced in the corresponding quarter in 2015. The Canadian industry continued to be dominated by horizontal and directional drilling representing 96 percent of all wells drilled. In the third quarter of 2016, the average number of horizontal and directional rigs running per day in the US decreased to 87 percent of all rigs running as compared to 93 percent in the third quarter of 2015. (Sources: Daily Oil Bulletin and Baker Hughes)
For the nine-month period ended September 30, 2016, consolidated revenue decreased by 56 percent to $101.8 million from $230.6 million in the comparable 2015-period. Consolidated operating days in the nine-month period ended September 30, 2016 were 10,462 which is 42 percent fewer than the 18,020 days reported in the 2015-period.
Operating Costs and Expenses
(Stated in thousands of dollars except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||
| Direct costs | 40,642 | 66,641 | (39 | ) | 122,906 | 222,198 | (45 | ) | ||||
| Gross profit (loss) as a percentage of revenue | (16 | %) | 2 | % | (21 | %) | 4 | % | ||||
| Depreciation & amortization (included in direct costs) | 11,851 | 14,903 | (20 | ) | 38,867 | 33,829 | 15 | |||||
| Gross profit as percentage of revenue excluding depreciation & amortization | 18 | % | 24 | % | 17 | % | 18 | % | ||||
Direct costs are comprised of field and shop expenses, and include depreciation and amortization on the Corporation’s equipment. For the three and nine-month periods ended September 30, 2016, direct costs decreased to $40.6 million and $122.9 million, respectively, from $66.6 million and $222.2 million in the comparable 2015-periods. The reduction in costs is consistent with the lower activity levels experienced in both 2016-periods. Included in direct costs for the three and nine-month periods ended September 30, 2016 is $0.4 million and $1.3 million of severance charges, respectively, as compared to $1.2 million and $3.9 million in the respective 2015-periods.
The gross loss as a percentage of revenue was 16 percent in the third quarter of 2016 compared to a gross profit percentage of 2 percent in 2015. Included in depreciation for the 2016 three-month period was depreciation of Stream assets of $0.7 million (2015- $1.1 million). Additionally, in the 2015-quarter a charge of $4.8 million pertaining to the removal of residual values of its drilling equipment was included in the depreciation expense. The Corporation’s lower activity levels and decreased average day rates generally caused the profit margin to decline in the third quarter of 2016.
For the nine-month period ended September 30, 2016, the gross loss as a percentage of revenue was 21 percent compared to a gross profit of 4 percent in the comparable 2015-period. Included in the depreciation for the 2016 nine-month period was depreciation of Stream assets of $2.9 million (2015 – $3.4 million). The lower gross profit percentages in 2016 were primarily due to higher depreciation and amortization expenses, reduced activity levels and decreased average day rates. The increased depreciation and amortization expense in the nine-month period ended September 30, 2016 was mainly the result of PHX Energy removing the residual values of its drilling equipment during a review completed in the third quarter of 2015.
Excluding depreciation and amortization, gross profit as a percentage of revenue decreased to 18 percent and 17 percent for the three and nine-month periods ended September 30, 2016 from 24 percent and 18 percent in the comparable 2015-periods. The decreased margins in both 2016-periods were primarily a result of lower activity levels and suppressed average day rates.
(Stated in thousands of dollars except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||
| Selling, general & administrative (“SG&A”) costs | 8,155 | 8,892 | (8 | ) | 21,714 | 29,619 | (27 | ) | ||||
| Share-based payments (recoveries) (included in SG&A costs) | 2,041 | (398 | ) | n.m. | 3,886 | 583 | n.m. | |||||
| SG&A costs excluding share-based payments as a percentage of revenue | 17 | % | 14 | % | 18 | % | 13 | % | ||||
SG&A costs for the three-month period ended September 30, 2016 decreased to $8.2 million, 8 percent lower than the $8.9 million incurred in 2015. Included in SG&A costs for the 2016-quarters were equity and cash-settled share-based payments of $2.0 million as compared to a $0.4 million recovery in the comparable 2015-quarter. Excluding these costs, SG&A costs as a percentage of consolidated revenue rose to 17 percent for the three-month period ended September 30, 2016 as compared to 14 percent in the 2015-period. In addition, included in SG&A costs for the three and nine-month periods ended September 30, 2016 were severance costs of $46,000 (2015 – $0.1 million) and $0.4 million (2015 – $1.5 million), respectively.
As the Corporation continued to align its cost structure with lower activity levels in all regions, SG&A costs incurred in dollar terms were reduced in both the three and nine-month periods ended September 30, 2016 over the comparable 2015-periods. These initiatives included reductions to personnel related costs and tightened policies on travel, entertainment, and marketing related costs.
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 both the three and nine-month periods ended September 30, 2016, equity-settled share-based payments increased by 68 percent as compared to the corresponding 2015-periods, generally due to compensation expenses related to options that were granted in the first quarter of 2016.
Cash-settled share-based retention awards, which are included in SG&A costs, are measured at fair value, and in the 2016-quarter the related compensation expense recognized by PHX Energy increased to $1.6 million as compared to a recovery of $0.7 million in the 2015-quarter. The increase is primarily due to the re-valuation of the retention awards based on the increase in PHX Energy’s stock price from $2.72 as at June 30, 2016 to $3.75 as at September 30, 2016.
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||
| Research & development expense | 582 | 615 | (5 | ) | 1,332 | 1,789 | (26 | ) |
The Corporation continued to closely monitor its research and development (“R&D”) expenditures in 2016. R&D expenditures for both the three-month periods ended September 30, 2016 and 2015 were $0.6 million. During both the 2016 and 2015-quarters, none of the R&D expenditures were capitalized as development costs.
For the nine-month period ended September 30, 2016, R&D expenditures incurred decreased by 26 percent to $1.3 million from $1.8 million in the corresponding 2015-period. The reduction to these expenditures in the 2016 nine-month period pertained mostly to the receipt of scientific research and experimental development tax credits totaling $0.3 million in the second quarter of 2016.
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||
| Finance expense | 352 | 698 | (50 | ) | 1,450 | 2,830 | (49 | ) |
Finance expenses relate to interest charges on the Corporation’s long-term and short-term bank facilities. As expected, finance charges decreased by 50 percent from $0.7 million in the third quarter of 2015 to $0.4 million in the 2016-quarter, and by 49 percent from $2.8 million in the nine-month period ended September 30, 2015 to $1.5 million in the comparable 2016-period. The decrease in both periods was due to the lower amount of borrowings outstanding during the three and nine-month periods ended September 30, 2016 that resulted from the significant repayments made in the 2016-periods.
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||
| 2016 | 2015 | 2016 | 2015 | |||||
| Gain (Loss) on disposition of drilling equipment | (62 | ) | (4,280 | ) | 717 | (3,673 | ) | |
| Foreign exchange gains (losses) | (59 | ) | 638 | 167 | 807 | |||
| Recovery of (Provision for) bad debts | (262 | ) | – | (196 | ) | (38 | ) | |
| Other Income (Expenses) | (383 | ) | (3,642 | ) | 688 | (2,904 | ) | |
For the three-month period ended September 30, 2016, the Corporation incurred other expenses of $0.4 million which was primarily the result of a $0.3 million increase to the provision for bad debts. These provisions relate mainly to US accounts receivables.
For the nine-month period ended September 30, 2016, other income is mainly comprised of gains on the disposition of drilling equipment of $0.7 million (2015 – loss of $3.7 million). 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 2016-periods, the gain on disposition of drilling equipment resulted primarily from insured lost equipment.
(Stated in thousands of dollars, except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||
| 2016 | 2015 | 2016 | 2015 | |||||
| Provision for (Recovery of) income taxes | (4,471 | ) | (7,123 | ) | (13,499 | ) | (10,348 | ) |
| Effective tax rates | 30 | % | 23 | % | 30 | % | 21 | % |
The recovery of income taxes for the three-month period ended September 30, 2016 was $4.5 million as compared to a recovery of $7.1 million in the 2015-quarter. For the nine-month period ended September 30, 2016, the recovery of income taxes was $13.5 million as compared to a recovery of $10.3 million in the corresponding 2015-period. The expected combined Canadian federal and provincial tax rate for 2016 is 27 percent. For both the three and nine-month periods ended September 30, 2016, the effective tax rate was higher than the expected rates primarily due to the effect of higher 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, mainly in Albania and Russia.
Canada
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||
| Revenue | 12,963 | 19,499 | (34 | ) | 34,415 | 69,319 | (50 | ) | ||||
| Reportable segment profit (loss) before tax | (4,028 | ) | (19,880 | ) | (80 | ) | (14,642 | ) | (29,361 | ) | (50 | ) |
For the three-month period ended September 30, 2016, Canadian revenue decreased by 34 percent to $13.0 million from $19.5 million in the corresponding 2015-period. The cause for this decrease was mainly lower industry activity and day rates realized in the 2016-quarter. The Canadian segment reported 1,751 operating days in the third quarter of 2016, a 16 percent decrease from the 2,075 days in the 2015-period. In contrast, total industry horizontal and directional drilling activity as measured by operating days, declined by 41 percent from 16,504 days in the 2015-quarter to 9,803 days in the equivalent 2016-quarter. (Source: Daily Oil Bulletin) Average day rates declined by 22 percent from $9,067 in the 2015-quarter to $7,096 in 2016, excluding Stream revenue of $0.5 million (2015 – $0.7 million).
The Corporation gained market share as compared to the prior year’s quarter as a result of its strong client relationships and operational performance. During the 2016-quarter, oil drilling, as measured by drilling days, represented approximately 53 percent of Canadian activity. PHX Energy was active in the Montney, Wilrich, Bakken, Shaunavon, Viking and Falher areas.
PHX Energy’s Canadian revenue for the nine-month period of 2016, decreased by 50 percent to $34.4 million from $69.3 million in the comparable 2015-period. The Corporation’s operating days decreased by 36 percent to 4,365 days in the 2016 nine-month period from 6,843 days in the 2015-period. In comparison, the number of horizontal and directional drilling days realized in the Canadian industry for the nine-month period ended September 30, 2016 decreased by 50 percent to 25,039 days from 49,623 days in the nine-month period of 2015. (Sources: Daily Oil Bulletin)
The Canadian operations’ reportable segment loss before tax for the third quarter of 2016 was $4.0 million as compared to a loss of $19.9 million in the 2015-quarter. For the nine-month period ended September 30, 2016, reportable segment loss before tax was $14.6 million as compared to a loss of $29.4 million in the 2015-period. The Canadian division’s losses in the 2015-periods contain $13.8 million in impairment losses on goodwill and intangible assets pertaining to the Stream division. The improved profitability margins in both 2016-periods are reflective of Management’s continued efforts to align the Corporation’s cost structure as activity and day rates decreased and the improved margins in the Stream division.
Included in the Canadian segment’s losses in the three and nine-month periods ended September 30, 2016 were Stream division losses of $1.5 million (2015 – $15.3 million) and $5.0 million (2015 – $20.1 million), respectively. Included in the Stream losses for both three and nine-month periods ended September 30, 2015 were $13.8 million of impairment losses pertaining to goodwill and intangible assets. Despite incremental costs associated with the commercialization of DataStream and wet weather causing delays in the deployment of systems, Stream’s margins improved in the current year. The Stream division is poised to expand operating activity without adding significant costs to its structure in future periods.
United States
(Stated in thousands of dollars)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||
| Revenue | 17,752 | 42,521 | (58 | ) | 56,872 | 142,498 | (60 | ) | ||||
| Reportable segment profit (loss) before tax | (8,042 | ) | (1,797 | ) | n.m. | (22,595 | ) | (7,754 | ) | n.m. | ||
n.m. – not meaningful
Revenue from PHX Energy’s US operations decreased 58 percent in the third quarter of 2016 to $17.8 million from $42.5 million in the 2015-quarter as a result of significant reductions in both industry rig count and continued day rate pricing pressures. In the third quarter, the average number of horizontal and directional rigs running per day decreased by 44 percent from 742 rigs in 2015 to 418 rigs in 2016. (Source: Baker Hughes) Activity levels in the US operating segment decreased as operating days fell 43 percent from 2,612 days in the 2015-quarter to 1,483 days in the 2016-quarter. Day rates in the US, excluding motor rentals, averaged $11,614 in the third quarter representing a 26 percent decrease from $15,725 achieved in the comparable 2015-period.
Horizontal and directional drilling continued to represent a large majority of wells drilled, averaging 87 percent of the rigs running on a daily basis in the third quarter of 2016. For the three-month period ended September 30, 2016, oil well drilling, as measured by wells drilled and excluding the motor rental and gyro surveying divisions, increased to 91 percent of PHX Energy’s US activity. During the third quarter of 2016, Phoenix USA remained active in the Permian, Eagle Ford, Mississippian/Woodford, Marcellus, Niobrara, Bakken and Utica basins.
US revenue decreased by 60 percent in the nine-month period ended September 30, 2016 to $56.9 million from $142.5 million in the comparable 2015-period. US operating days in the 2016 nine-month period decreased 52 percent to 4,321 days from 9,042 days in the 2015-period. In comparison, US industry activity, as measured by the average number of horizontal and directional rigs running on a daily basis, decreased by 53 percent in the nine-month period of 2016 to 424 rigs from 907 rigs in the comparable 2015-period. (Source: Baker Hughes)
Reportable segment loss before tax for the three-month period ended September 30, 2016 was $8.0 million compared to a loss of $1.8 million in the 2015-quarter. For the nine-month period ended September 30, 2016, reportable segment loss before tax was $22.6 million compared to a loss of $7.8 million in the comparative 2015-period. The significant decrease in profitability experienced in both 2016-periods is reflective of the US rig count recording a thirty-year low which consequently caused increased day rate pricing pressures.
International
(Stated in thousands of dollars, except percentages)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | |||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||
| Revenue | 4,249 | 6,207 | (32 | ) | 10,485 | 18,825 | (44 | ) | ||||
| Reportable segment profit (loss) before tax | 267 | 797 | (66 | ) | (1,466 | ) | 3,554 | n.m. | ||||
| Reportable segment profit before tax as a percentage of revenue | 6 | % | 13 | % | n.m. | 19 | % | |||||
n.m. – not meaningful
The Corporation’s international revenue decreased by 32 percent from $6.2 million in the third quarter of 2015 to $4.2 million in 2016. International operating days in the third quarter of 2016 were comprised entirely of Russian activity and increased slightly to 708 days from the 2015-quarter when there was 700 days generated in both Russia and Albania. The Corporation generated 12 percent of its consolidated revenue from its international operations in the 2016-quarter, which is up from the 9 percent reported in the 2015-quarter.
For the nine-month period ended September 30, 2016, revenue decreased by 44 percent to $10.5 million from $18.8 million in the comparable 2015-period. International operating days were down 17 percent in the nine-month period of 2016 totaling 1,776 days, as compared to the 2,135 days in the 2015-period. The decreased revenue and operating day totals for the 2016 nine-month period were the result of idle operations in Albania.
Russian revenue in the third quarter of 2016 rose to $4.2 million, which is 24 percent greater than $3.4 million recorded in the comparable 2015-quarter. The revenue growth was largely attributable to the 42 percent increase in activity as the division recorded 708 operating days in the third quarter of 2016, compared to the 497 days recorded in the same quarter of 2015.
For the third consecutive quarter, the Albania division remained idle recording zero days of activity as compared to 203 days in the 2015-quarter. During the third quarter of 2016, the Corporation was awarded a new drilling contract in Albania and operations commenced in the fourth quarter.
Reportable segment profit from international operations for the three-month period ended September 30, 2016 was $0.3 million (6 percent of revenue), which is 66 percent lower than the $0.8 million (13 percent of revenue) generated in the corresponding 2015-period. Reportable segment loss for the nine-month period ended September 30, 2016 was $1.5 million as compared to a profit of $3.6 million (19 percent of revenue) in the 2015-period. The decrease in the international operations’ profitability in both 2016-periods was a result of the idle operations in Albania.
Investing Activities
Net cash used in investing activities for the three-month period ended September 30, 2016 was $2.0 million as compared to $8.1 million in 2015. During the third quarter of 2016, the Corporation acquired $2.4 million of drilling and other equipment (2015 – $2.3 million) and received proceeds of $0.4 million from the disposition of drilling equipment, primarily related to involuntary disposal of drilling equipment in well bores (2015 – $0.7 million). The quarterly 2016 expenditures included:
- $1.7 million in measurement while drilling (“MWD”) systems and spare components;
- $0.5 million in electronic drilling recorder equipment;
- $0.2 million in machinery and equipment and leasehold improvements.
The capital expenditure program undertaken in the period was financed generally from working capital.
During the 2016-quarter, the Corporation spent $1.3 million on intangible assets related to committed license payments.
The change in non-cash working capital balances of $1.2 million (source of cash) for the three-month period ended September 30, 2016, relates to the net change in the Corporation’s trade payables that are associated with the acquisition of capital assets. This compares to $0.7 million (use of cash) for the three-month period ended September 30, 2015.
Financing Activities
The Corporation reported cash flows from financing activities of $2.5 million in the three-month period ended September 30, 2016 as compared to cash flows used in financing activities of $3.2 million in the comparable 2015-period. The Corporation drew net proceeds of $2.5 million on its operating and syndicated facilities during the third quarter of 2016.
Capital Resources
As of September 30, 2016, the Corporation had $20.0 million drawn on its syndicated facility, $8.9 million drawn on its operating facility, and nil drawn on its US operating facility. At September 30, 2016, the Corporation had approximately CDN$56.1 million and US$2.5 million available to be drawn from its credit facilities.
As at September 30, 2016, the Corporation was in compliance with all its financial covenants.
Subsequent to September 30, 2016, the Corporation amended its credit agreement with its syndicate of lenders. The key amendments included:
- The Corporation further reduced the maximum principal amounts available under the Syndicated Credit Facility from CDN$70.0 million to CDN$48.0 million, the Operating Facility from CDN$15.0 million to CDN$10.0 million and the US Operating Facility from US$2.5 million to US$1.5 million. The purpose of the decrease was to reduce the standby fees charged on unused balances under the credit facilities.
- The debt to covenant EBITDA ratio and interest coverage ratio will be waived from the quarter ending December 31, 2016 to the quarter ending June 30, 2017, inclusive.
- During those quarters where the debt to covenant EBITDA ratio and interest coverage ratio are waived, the Corporation will be subject to a minimum liquidity test in which the Corporation’s cash on hand plus cash available under its Credit Facilities must exceed CDN$10.0 million.
- For the periods ending December 31, 2016 and thereafter, the following covenant EBITDA formulae and financial covenants will come in to effect:
| Quarter Ending | Covenant EBITDA Formula | Debt to Covenant EBITDA Ratio | Interest Coverage Ratio | |||
| Dec. 31, 2016 | Covenant EBITDA for the trailing twelve-month period | Waived | Waived | |||
| Mar. 31, 2017 | Covenant EBITDA for the trailing twelve-month period | Waived | Waived | |||
| June 30, 2017 | Covenant EBITDA for the trailing twelve-month period | Waived | Waived | |||
| Sept. 30, 2017 | Covenant EBITDA for the three-month period ending September 30, 2017 multiplied by 4 | < 4.0x | > 3.0x | |||
| Dec. 31, 2017 | Covenant EBITDA for the six-month period ending December 31, 2017 multiplied by 2 | < 4.0x | > 3.0x | |||
| Mar. 31, 2018 | Covenant EBITDA for the nine-month period ending March 31, 2018 multiplied by 4 and divided by 3 | < 3.5x | > 3.0x | |||
| June 30, 2018 | Covenant EBITDA for the trailing twelve-month period ending June 30, 2018 | < 3.5x | > 3.0x | |||
| Quarters ending thereafter | Covenant EBITDA for the trailing twelve-month period | < 3.0x | > 3.0x |
- An additional negative covenant which caps the Corporation’s net capital expenditures and intangible costs in aggregate of $42.8 million from fiscal years 2016 to 2018.
- Until September 30, 2017, the applicable pricing on borrowings shall be fixed, at the Corporation’s option, at the bank’s prime plus a margin of 3.5 percent for base loans, or the banker’s acceptance rate plus a margin of 4.5 percent.
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 Corporation’s 2016 capital budget remains at $8.1 million and will be used mainly to fund the continued expansion of the Corporation’s DataStream EDR and Velocity Real-Time System (“Velocity”) fleets. 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 2016, 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 combination of lower activity and increased day rate pressures in a down turn market have continued to impact the Corporation’s financial results for the third quarter of 2016. Activity levels and profitability decreased compared to the prior year’s quarter. Despite the challenges faced, PHX Energy continued to push forward key strategic objectives focused on improving margins and gaining market share, and believes these initiatives will be beneficial as the industry rig counts are heading in a positive direction. Today, all of the Corporation’s operating regions and divisions are experiencing an uptick in activity levels.
North American drilling activity appears to have bottomed earlier this year and the industry is now seeing a steady increase in active rigs, particularly in the US. Currently there are approximately 570 active rigs operating in the US market, this compares to a low in the second quarter of approximately 400 rigs. Sixty percent of these additional rigs were deployed in the Permian Basin in west Texas and eastern New Mexico, and PHX Energy is diligently focused on capturing market share in this growing market.
In the third quarter, the Canadian rig count began to recover from the lowest levels of activity seen in several decades. Currently the rig count is approximately 150 rigs, a sharp contrast from the 40 rigs operating during the spring break-up period. Unfortunately, the recovery was slower than anticipated due to unusually wet weather during the third quarter and at the start of the fourth quarter, particularly in the Saskatchewan and eastern Alberta regions. The Corporation experienced delays in drilling projects during the first part of the fourth quarter both in its directional drilling and Stream EDR divisions as a result of operators not being able to move heavy equipment.
Internationally, PHX Energy’s Russian operations experienced growth in the third quarter of 2016. PHX Energy is cautiously optimistic about the growth of its international division. It believes activity in Russia will continue to increase in upcoming quarters as the Corporation expands its footprint. In Albania, PHX Energy was awarded a new drilling contract which began in the fourth quarter and further growth is projected into 2017.
One of the technologies that is creating competitive advantages for PHX Energy is its Velocity Real-Time System. Operators are recognizing the benefits of the advanced measurements and faster, more reliable transmission Velocity offers. To meet demands for the system, the Corporation will double its Velocity job capacity to 35 jobs per day by the middle of the fourth quarter. Velocity has been particularly successful in gaining market share in the Permian Basin and PHX Energy will leverage the larger fleet to capture additional rigs in this, the most active basin in North America.
The Corporation announced the commercialization of Stream’s new EDR product line during the third quarter. The launch of this product line will allow the Corporation to successfully diversify its business with a competitive service offering in an attractive sector of the market with very few competitors and historically attractive margins. Stream has been quick to gain market acceptance since the commercialization announcement in early September and the Corporation intends to double Stream’s 15 job capacity during the course of the fourth quarter. PHX Energy anticipates that this increased capacity will reduce the losses that have been incurred in the past quarters and sees the division achieving profits in the future quarters. Stream has been entirely focused on one geographical area in western Canada, and the Corporation anticipates expanding into new areas in the upcoming year.
Industry conditions are improving and PHX Energy has some exciting products that will fuel future growth although challenges remain. The Corporation needs to see a prolonged period of increased rig counts in all operating regions in order to see some much needed pricing improvements and ultimately higher margins. PHX Energy remains focused on its core strategic goals of providing differentiating technology, operating a lean, efficient company and seeking additional opportunities in higher margin segments of the drilling industry.
– Michael Buker, President
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, | ||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||
| Net loss | (10,679 | ) | (24,515 | ) | (31,442 | ) | (38,707 | ) | |
| Add: | |||||||||
| Depreciation and amortization | 11,851 | 14,903 | 38,867 | 33,830 | |||||
| Provision for (Recovery of) income taxes | (4,471 | ) | (7,123 | ) | (13,499 | ) | (10,348 | ) | |
| Finance expense | 352 | 698 | 1,450 | 2,830 | |||||
| Impairment losses on goodwill and intangible assets | – | 13,823 | – | 13,823 | |||||
| Provision for settlement of litigations | – | 5,555 | – | 6,533 | |||||
| Share-based payments (recoveries) | 2,041 | (398 | ) | 3,886 | 583 | ||||
| Severance costs | 374 | 1,286 | 1,703 | 5,527 | |||||
| Other non-cash charges | 300 | – | 900 | – | |||||
| Adjusted EBITDA as reported | (232 | ) | 4,229 | 1,865 | 13,968 | ||||
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, | |||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||
| Cash flows from operating activities | (100 | ) | 10,780 | 4,732 | 42,950 | |||||
| Add (deduct): | ||||||||||
| Changes in non-cash working capital | (2,038 | ) | (9,994 | ) | (3,261 | ) | (42,750 | ) | ||
| Interest paid | 221 | 575 | 982 | 2,339 | ||||||
| Income taxes received | 23 | (684 | ) | (3,955 | ) | 1,778 | ||||
| Funds from operations | (1,894 | ) | 677 | (1,502 | ) | 4,317 | ||||
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) Debt to covenant EBITDA Ratio
Debt is represented by loans and borrowings. Covenant EBITDA, for purposes of the calculation of this covenant ratio, is represented by net earnings for a rolling four quarter period, adjusted for finance expense, provision for income taxes, depreciation and amortization, equity-settled share-based payments, unrealized foreign exchange losses, impairment losses on goodwill and intangible assets, loss on disposition of drilling equipment, severance costs, provision for inventory obsolescence and provision for the settlement of litigations, subject to the restrictions provided in the amended credit agreement.
The debt to covenant EBITDA ratio is waived from the quarter ending December 31, 2016 to the quarter ending June 30, 2017, inclusive.
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 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 centers 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; Midland, Texas; Bellaire, Ohio; and Oklahoma City, Oklahoma. Internationally, PHX Energy has sales offices and service facilities in Russia and Albania, and administrative offices in Nicosia, Cyprus 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.
Consolidated Statements of Financial Position
(unaudited)
| September 30, 2016 | December 31, 2015 | ||||||
| ASSETS | |||||||
| Current assets: | |||||||
| Cash and cash equivalents | $ | 2,591,005 | $ | 9,007,808 | |||
| Trade and other receivables | 32,408,696 | 44,694,812 | |||||
| Inventories | 27,094,617 | 30,261,260 | |||||
| Prepaid expenses | 2,823,145 | 2,869,018 | |||||
| Current tax assets | 6,359,319 | 4,996,279 | |||||
| Total current assets | 71,276,782 | 91,829,177 | |||||
| Non-current assets: | |||||||
| Drilling and other equipment | 128,648,109 | 166,113,852 | |||||
| Goodwill | 8,876,351 | 8,876,351 | |||||
| Intangible assets | 25,298,568 | 25,025,202 | |||||
| Deferred tax assets | 10,038,267 | 1,581,847 | |||||
| Total non-current assets | 172,861,295 | 201,597,252 | |||||
| Total assets | $ | 244,138,077 | $ | 293,426,429 | |||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||
| Current liabilities: | |||||||
| Operating facility | $ | 8,869,361 | $ | – | |||
| Trade and other payables | 24,085,293 | 30,373,003 | |||||
| Dividends payable | – | 415,670 | |||||
| Total current liabilities | 32,954,654 | 30,788,673 | |||||
| Non-current liabilities: | |||||||
| Loans and borrowings | 20,000,000 | 60,000,000 | |||||
| Deferred income | 1,600,004 | 1,700,003 | |||||
| Total non-current liabilities | 21,600,004 | 61,700,003 | |||||
| Equity: | |||||||
| Share capital | 237,240,665 | 213,604,045 | |||||
| Contributed surplus | 6,756,288 | 5,390,124 | |||||
| Retained earnings | (67,835,962 | ) | (36,393,629 | ) | |||
| Accumulated other comprehensive income | 13,422,428 | 18,337,213 | |||||
| Total equity | 189,583,419 | 200,937,753 | |||||
| Total liabilities and equity | $ | 244,138,077 | $ | 293,426,429 | |||
Consolidated Statements of Comprehensive Income
(unaudited)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||
| Revenue | $ | 34,964,130 | $ | 68,227,342 | $ | 101,772,027 | $ | 230,641,748 | |||||
| Direct costs | 40,642,117 | 66,640,879 | 122,905,878 | 222,198,203 | |||||||||
| Gross profit (loss) | (5,677,987 | ) | 1,586,463 | (21,133,851 | ) | 8,443,545 | |||||||
| Expenses: | |||||||||||||
| Selling, general and administrative expenses | 8,155,063 | 8,891,741 | 21,713,636 | 29,619,318 | |||||||||
| Provision for the settlement of litigations | – | 5,555,453 | – | 6,533,426 | |||||||||
| Research and development expenses | 581,893 | 614,745 | 1,331,867 | 1,789,359 | |||||||||
| Finance expense | 351,525 | 697,513 | 1,450,339 | 2,829,747 | |||||||||
| Impairment losses on goodwill and intangible assets | – | 13,823,514 | – | 13,823,514 | |||||||||
| Other expenses (income) | 383,116 | 3,642,073 | (687,981 | ) | 2,903,859 | ||||||||
| 9,471,597 | 33,225,039 | 23,807,861 | 57,499,223 | ||||||||||
| Loss before income taxes | (15,149,584 | ) | (31,638,576 | ) | (44,941,712 | ) | (49,055,678 | ) | |||||
| Provision for (Recovery of) income taxes | |||||||||||||
| Current | (19,295 | ) | (2,541,157 | ) | (5,303,499 | ) | (1,562,740 | ) | |||||
| Deferred | (4,451,466 | ) | (4,581,993 | ) | (8,195,880 | ) | (8,785,661 | ) | |||||
| (4,470,761 | ) | (7,123,150 | ) | (13,499,379 | ) | (10,348,401 | ) | ||||||
| Net loss | (10,678,823 | ) | (24,515,426 | ) | (31,442,333 | ) | (38,707,277 | ) | |||||
| Other comprehensive income (loss) | |||||||||||||
| Foreign currency translation | 1,936,330 | 5,767,432 | (4,914,785 | ) | 15,462,299 | ||||||||
| Total comprehensive loss for the period | $ | (8,742,493 | ) | $ | (18,747,994 | ) | $ | (36,357,118 | ) | $ | (23,244,978 | ) | |
| Loss per share – basic | $ | (0.21 | ) | $ | (0.59 | ) | $ | (0.70 | ) | $ | (1.03 | ) | |
| Loss per share – diluted | $ | (0.21 | ) | $ | (0.59 | ) | $ | (0.70 | ) | $ | (1.03 | ) | |
Consolidated Statements of Cash Flows
(unaudited)
| Three-month periods ended September 30, | Nine-month periods ended September 30, | ||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||
| Cash flows from operating activities: | |||||||||||||
| Net loss | $ | (10,678,823 | ) | $ | (24,515,426 | ) | $ | (31,442,333 | ) | $ | (38,707,277 | ) | |
| Adjustments for: | |||||||||||||
| Depreciation and amortization | 11,851,226 | 14,902,807 | 38,866,653 | 33,829,413 | |||||||||
| Provision for (Recovery of) income taxes | (4,470,761 | ) | (7,123,150 | ) | (13,499,379 | ) | (10,348,401 | ) | |||||
| Unrealized foreign exchange loss (gain) | (17,662 | ) | (661,676 | ) | 1,467,103 | (1,540,156 | ) | ||||||
| Loss (Gain) on disposition of drilling equipment | 61,872 | 4,279,862 | (717,121 | ) | 3,672,988 | ||||||||
| Impairment loss on goodwill and intangible assets | – | 13,823,514 | – | 13,823,514 | |||||||||
| Equity-settled share-based payments | 479,780 | 285,279 | 1,377,014 | 818,514 | |||||||||
| Finance expense | 351,525 | 697,513 | 1,450,339 | 2,829,747 | |||||||||
| Amortization of deferred income | (33,333 | ) | (33,333 | ) | (99,999 | ) | (99,999 | ) | |||||
| Provision for bad debts | 261,970 | – | 196,278 | 38,407 | |||||||||
| Other non-cash charges | 300,000 | (977,973 | ) | 899,899 | – | ||||||||
| Change in non-cash working capital | 2,038,048 | 9,994,349 | 3,261,005 | 42,750,091 | |||||||||
| Cash generated from operating activities | 143,842 | 10,671,766 | 1,759,459 | 47,066,841 | |||||||||
| Interest paid | (221,159 | ) | (575,969 | ) | (981,588 | ) | (2,339,511 | ) | |||||
| Income taxes received (paid) | (22,868 | ) | 684,449 | 3,954,506 | (1,777,689 | ) | |||||||
| Net cash from (used in) operating activities | (100,185 | ) | 10,780,246 | 4,732,377 | 42,949,641 | ||||||||
| Cash flows from investing activities: | |||||||||||||
| Proceeds on disposition of drilling equipment | 359,365 | 653,040 | 3,214,891 | 3,322,993 | |||||||||
| Acquisition of drilling and other equipment | (2,364,577 | ) | (2,338,258 | ) | (5,256,107 | ) | (17,155,565 | ) | |||||
| Acquisition of intangible assets | (1,255,709 | ) | (5,676,534 | ) | (2,188,061 | ) | (7,862,039 | ) | |||||
| Change in non-cash working capital | 1,235,277 | (723,817 | ) | 1,401,157 | (3,459,060 | ) | |||||||
| Net cash used in investing activities | (2,025,644 | ) | (8,085,569 | ) | (2,828,120 | ) | (25,153,671 | ) | |||||
| Cash flows from financing activities: | |||||||||||||
| Proceeds from (Payments for) issuance of share capital (net) | 22,230 | (34,018 | ) | 23,243,889 | 34,311,343 | ||||||||
| Dividends paid to shareholders | – | (2,181,391 | ) | (415,670 | ) | (12,680,532 | ) | ||||||
| Proceeds from (Repayment of) loans and borrowings | (2,095,010 | ) | 3,000,000 | (40,018,640 | ) | (34,280,800 | ) | ||||||
| Payments under finance leases | – | (5,478 | ) | – | (92,858 | ) | |||||||
| Proceeds from (Repayment of) operating facility | 4,574,849 | (4,001,344 | ) | 8,869,361 | (5,200,246 | ) | |||||||
| Net cash from (used in) financing activities | 2,502,069 | (3,222,231 | ) | (8,321,060 | ) | (17,943,093 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | 376,240 | (527,554 | ) | (6,416,803 | ) | (147,123 | ) | ||||||
| Cash and cash equivalents, beginning of period | 2,214,765 | 3,398,876 | 9,007,808 | 3,018,445 | |||||||||
| Cash and cash equivalents, end of period | $ | 2,591,005 | $ | 2,871,322 | $ | 2,591,005 | $ | 2,871,322 | |||||
| (1) | Please refer to the non-GAAP measures section following the Outlook section for applicable definitions and reconciliations. |
John Hooks
CEO
Tel: 403-543-4466
403-543-4485 (FAX)
Michael Buker
President
Tel: 403-543-4466
403-543-4485 (FAX)
Cameron Ritchie
Senior Vice President Finance and CFO
Tel: 403-543-4466
403-543-4485 (FAX)
www.phxtech.com