CALGARY, ALBERTA--(Marketwired - Nov. 4, 2015) - PHX Energy Services Corp. (TSX:PHX) -
Financial Results
In the three-month period ended September 30, 2015 adjusted EBITDA was $8.9 million (13 percent of revenue), which is 66 percent lower than the $25.9 million (19 percent of revenue) reported in the comparable 2014-period. Adjusted EBITDA is defined as earnings before finance expense, income taxes, depreciation and amortization ("EBITDA"), loss on disposition of drilling equipment, impairment losses on goodwill and intangible assets, provisions for the settlement of litigations, and severance costs (see Non-GAAP measures section). This decrease was primarily due to weak activity levels and lower average day rates realized in the 2015-quarter. However, relative to the first quarter of 2015 when adjusted EBITDA was 7 percent of revenue, profitability has significantly improved as adjusted EBITDA represented 13 percent of revenue in the third quarter of 2015. These positive results were primarily driven by the various initiatives that were implemented by Management to align the Corporation's cost structure with contracted activity levels.
For the three-month period ended September 30, 2015, PHX Energy generated consolidated revenue of $68.2 million, 51 percent lower than the $139.0 million generated in the 2014-period. This decrease is mainly due to lower industry activity and pricing pressures in all of the Corporation's operating segments. In the three-month period ended September 30, 2015, PHX Energy reported a net loss of $24.5 million compared to net earnings of $13.0 million in the third quarter of 2014. The net loss incurred during the 2015-quarter was mainly due to the recognition of the following charges (pre-tax): a provision of $5.6 million relating to the settlement of litigations in the US, a $13.8 million impairment loss on the goodwill and intangible assets related to the Corporation's Stream Services ("Stream") cash-generating unit ("CGU"), a $4.3 million loss on the disposition of equipment primarily due to decommissioned assets, and $4.8 million of additional depreciation and amortization expenses that resulted from a change in the Corporation's estimate of the residual values of its drilling equipment.
As at September 30, 2015, PHX Energy had long-term debt of $70.0 million and working capital of $59.8 million.
Provisions
In September, 2015, the Corporation's wholly-owned subsidiary, Phoenix Technology Services USA Inc. ("Phoenix USA") and the parties to the collective and class actions in the US entered into a settlement agreement wherein the parties have agreed for the full and final release and dismissal of all claims and allegations made in the collective and class actions, by the establishment of a US$5.0 million (equivalent to CDN$6.5 million) settlement fund, which shall be funded by the Corporation in three equal installments on November 2, 2015, January 1, 2016 and January 31, 2016. The settlement agreement includes all measurement while drilling ("MWD") operators employed by Phoenix USA, regardless of the states in which they worked and whether they had already joined one of the pending lawsuits. In October, 2015, the Corporation received the requisite court approval of the settlement agreement. During the three-month period ended September 30, 2015, PHX Energy recognized a provision of $5.6 million for the settlement.
Goodwill and Intangible Asset Impairment
In the third quarter of 2015, the Corporation recognized an impairment loss of $13.8 million related to its Stream CGU. Of the impairment loss, $7.3 was allocated to goodwill and $6.5 million was allocated to intangible assets, which are comprised of $5.8 million relating to an old version of the electronic drilling recorder ("EDR") technology and $0.7 million relating to a customer relationship.
Change in Estimate
In September, 2015, the Corporation reviewed the residual values of its drilling equipment and now expects it to be nil instead of its previous estimate of zero to 20 percent of acquisition cost. The effect of this change was an increase of $4.8 million in the depreciation expense for the 2015-quarter.
Severance
As a result of Management's continued efforts to align the Corporation's cost structure with the lower activity levels, severance payments of $1.3 million and $5.4 million, included in direct costs and SG&A, were incurred in the three and nine-month periods ended September 30, 2015, respectively.
Capital Spending
To preserve cash flows, the Corporation was cautious with its capital spending. For the three-month period ended September 30, 2015, only $2.3 million in capital expenditures were incurred, which is 93 percent less than the $31.2 million incurred in the comparable 2014-period. At the end of September, 2015, an additional $0.8 million of equipment is on order, which is expected to be received within the next quarter. It is expected that $18.5 million in capital expenditures will be spent in the 2015-year.
Amendments to Credit Facilities
On October 16, 2015, the Corporation amended its credit agreement with its syndicate of lenders. The amendments reflected relaxations on its financial and negative covenants for periods up to the quarter ended March, 2017. The maximum principal amounts available to the Corporation under the credit facilities were also reduced to lessen the standby fees charged on unused balances under the credit facilities.
Dividends
During the third quarter of 2015, the Corporation paid dividends of $2.2 million or $0.05 per share. As previously announced, the Board of Directors (the "Board") approved a reduction to PHX Energy's monthly dividend from $0.0175 per share per month to $0.0033 per share per month effective for the September dividend. Following payment of the September dividend, the Corporation has transitioned to a quarterly dividend payment structure.
PHX Energy announces that the Board has declared a quarterly dividend of $0.01 per share effective for the fourth quarter of 2015, payable on January 15, 2016 to shareholders of record at the close of business on December 31, 2015. The ex-dividend date is December 29, 2015. The dividend is designated as an "eligible dividend" within the meaning of subsection 89(1) of the Income Tax Act (Canada).
| |
|
| Financial Highlights |
|
| (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, |
|
| |
2015 |
|
2014 |
|
%
Change |
|
2015 |
|
2014 |
|
%
Change |
|
| Operating Results |
(unaudited |
) |
(unaudited |
) |
|
|
(unaudited |
) |
(unaudited |
) |
|
|
| Revenue |
68,227 |
|
138,971 |
|
(51 |
) |
230,642 |
|
368,586 |
|
(37 |
) |
| Net earnings (loss) |
(24,515 |
) |
13,024 |
|
n.m. |
|
(38,707 |
) |
20,775 |
|
n.m. |
|
| Earnings (Loss) per share - diluted |
(0.59 |
) |
0.37 |
|
n.m. |
|
(1.03 |
) |
0.59 |
|
n.m. |
|
| Adjusted EBITDA (1) |
8,906 |
|
25,889 |
|
(66 |
) |
17,058 |
|
53,197 |
|
(68 |
) |
| Adjusted EBITDA per share - diluted (1) |
0.21 |
|
0.73 |
|
(71 |
) |
0.46 |
|
1.52 |
|
(70 |
) |
| Adjusted EBITDA as a percentage of revenue (1) |
13% |
|
19% |
|
|
|
7% |
|
14% |
|
|
|
| Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash flows from operating activities |
10,780 |
|
(1,735 |
) |
n.m. |
|
42,950 |
|
17,664 |
|
143 |
|
| Funds from operations (1) |
677 |
|
26,702 |
|
(97 |
) |
4,317 |
|
53,720 |
|
(92 |
) |
| Funds from operations per share - diluted (1) |
0.02 |
|
0.75 |
|
(97 |
) |
0.12 |
|
1.53 |
|
(92 |
) |
| Dividends paid |
2,181 |
|
7,356 |
|
(70 |
) |
12,681 |
|
21,808 |
|
(42 |
) |
| Dividends per share (2) |
0.05 |
|
0.21 |
|
(76 |
) |
0.35 |
|
0.63 |
|
(44 |
) |
| Capital expenditures |
2,338 |
|
31,236 |
|
(93 |
) |
17,156 |
|
55,761 |
|
(69 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Financial Position (unaudited) |
|
|
|
|
|
|
Sep 30, '15 |
|
Dec 31, '14 |
|
|
|
| Working capital |
|
|
|
|
|
|
59,809 |
|
80,974 |
|
(26 |
) |
| Long-term debt |
|
|
|
|
|
|
70,000 |
|
104,281 |
|
(33 |
) |
| Shareholders' equity |
|
|
|
|
|
|
202,086 |
|
199,961 |
|
1 |
|
| Common shares outstanding |
|
|
|
|
|
|
41,565,727 |
|
35,237,839 |
|
18 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| n.m. - not meaningful |
| (1) Refer to non-GAAP measures 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 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.
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, 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: "Overall Performance" 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; tax laws; 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, |
|
| |
2015 |
2014 |
%
Change |
|
2015 |
2014 |
%
Change |
|
| Revenue |
68,227 |
138,971 |
(51 |
) |
230,642 |
368,586 |
(37 |
) |
| |
|
|
|
|
|
|
|
|
Industry activity in all of the Corporation's operating segments remained weak and pricing pressures continued to mount as depressed oil prices carried through the third quarter of 2015. For the three-month period ended September 30, 2015, consolidated revenue decreased by 51 percent to $68.2 million compared to $139.0 million in the comparable 2014-period. US and international revenue as a percentage of total consolidated revenue were 62 and 9 percent, respectively, for the 2015-quarter as compared to 55 and 9 percent in 2014. Consolidated operating days decreased by 49 percent to 5,387 days as compared to 10,462 days in the 2014-quarter. Average consolidated day rates for the three-month period ended September 30, 2015, excluding the motor rental division in the US and the Stream division, decreased by 3 percent to $12,269 from $12,701 in the third quarter of 2014. Excluding the impact of US foreign exchange, average consolidated day rates for the three-month period ended September 30, 2015 decreased by 13 percent to $10,996.
In the 2015-quarter North American rig counts remained approximately 50 percent lower than the rig count experienced in the corresponding quarter in 2014. The Canadian industry continued to be dominated by horizontal and directional drilling, 96 percent of all wells drilled, and in the US the average number of horizontal and directional rigs running per day increased to 86 percent of all rigs running as compared to 80 percent in the third quarter of 2014. (Sources: Daily Oil Bulletin and Baker Hughes)
For the nine-month period ended September 30, 2015, consolidated revenue decreased by 37 percent to $230.6 million from $368.6 million in the comparable 2014-period. There were 18,020 consolidated operating days in the nine-month period ended September 30, 2015, which is 35 percent lower than the 27,730 days reported in the 2014-period.
| |
|
| Operating Costs and Expenses |
|
| (Stated in thousands of dollars except percentages) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
2014 |
%
Change |
|
2015 |
2014 |
%
Change |
|
| Direct costs |
66,641 |
107,927 |
(38 |
) |
222,198 |
294,904 |
(25 |
) |
| Gross profit as a percentage of revenue |
2% |
22% |
|
|
4% |
20% |
|
|
| Depreciation & amortization (included in direct costs) |
14,903 |
8,207 |
82 |
|
33,829 |
23,138 |
46 |
|
| Gross profit as percentage of revenue excluding depreciation & amortization |
24% |
28% |
|
|
18% |
26% |
|
|
| |
|
|
|
|
|
|
|
|
Direct costs are comprised of field and shop expenses, and include depreciation and amortization on the Corporation's equipment. In the third quarter of 2015, gross profit as a percentage of revenue decreased to 2 percent from 22 percent in the 2014-quarter, and in the 2015 nine-month period decreased to 4 percent of revenue from 20 percent in the comparable 2014-period. The decrease in gross profit as a percentage of revenue was partly due to higher depreciation and amortization expenses in the three-month period ended September 30, 2015 which increased by 82 percent to $14.9 million as compared to $8.2 million in the 2014-quarter. The increase in depreciation and amortization expenses in the three and nine-month period ended September 30, 2015 was mainly the result of the Corporation's high level of capital expenditures in 2014. In addition in September, 2015, the Corporation reviewed the residual values of its drilling equipment and now expects it to be nil instead of its previous estimate of zero to 20 percent of acquisition cost. The effect of this change was an increase of $4.8 million in the depreciation expense for the 2015-quarter.
Excluding depreciation and amortization, gross profit as a percentage of revenue decreased to 24 percent for the three-month period ended September 30, 2015 from 28 percent in the comparable 2014-period. For the nine-month period ended September 30, 2015, gross profit as a percentage of revenue, excluding depreciation and amortization, was 18 percent of revenue as compared to 26 percent in 2014.
The decrease in margins in both the three and nine-month periods ended September 30, 2015 was, as in previous 2015-quarters, mainly due to lower activity and significant pricing pressures experienced in all of the Corporation's operating segments. In addition, as a result of Management's continued efforts to align the cost structure with activity levels, severance payments of $1.2 million and $3.9 million (included in direct costs) were incurred in the three and nine-month periods ended September 30, 2015, respectively.
Relative to the first and second quarter of the 2015-year, PHX Energy's profitability improved as gross profit as a percentage of revenue, excluding depreciation and amortization, increased to 24 percent in the third quarter of 2015 from 16 percent in both the first and second quarters of 2015. These positive results were largely driven by Management's implementation of several initiatives that were focused on optimizing resources, including the reduction of labor costs and improving equipment repair rates.
For the three-month period ended September 30, 2015, the Corporation's third party equipment rentals were 4 percent of consolidated revenue, which is the same percentage as in the corresponding 2014-quarter.
| |
|
| (Stated in thousands of dollars except percentages) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
2014 |
%
Change |
|
2015 |
2014 |
%
Change |
|
| Selling, general & administrative ("SG&A") costs |
8,892 |
13,973 |
(36 |
) |
29,619 |
43,101 |
(31 |
) |
| Equity-settled share-based payments (included in SG&A costs) |
285 |
207 |
38 |
|
819 |
621 |
32 |
|
| SG&A costs excluding equity-settled share-based payments as a percentage of revenue |
13% |
10% |
|
|
12% |
12% |
|
|
| |
|
|
|
|
|
|
|
|
SG&A costs for the three-month period ended September 30, 2015 decreased by 36 percent to $8.9 million as compared to $14.0 million in 2014. Included in SG&A costs for the 2015 and 2014-quarters are equity-settled share-based payments of $0.3 million and $0.2 million, respectively. Excluding these costs, SG&A costs as a percentage of consolidated revenue for the three-month periods ended September 30, 2015 and 2014 were 13 percent and 10 percent, respectively. Also included in SG&A costs for the three and nine-month periods ended September 30, 2015 were severance costs of $0.1 million and $1.5 million, respectively.
In the 2015-periods, SG&A costs incurred in dollar terms decreased mainly as a result of initiatives carried out to align the Corporation's cost structure with the lower activity in all regions. These initiatives included reductions to personnel related costs and tightened policies on travel, entertainment, and marketing related costs. In addition, in the 2015-periods the SG&A costs were less as a result of lower compensation expenses related to the cash-settled share-based retention awards, which are valued based on the price of PHX Energy's shares.
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, 2015, equity-settled share-based payments increased by 38 and 32 percent, respectively, as compared to the corresponding 2014-periods, generally due to compensation expenses related to options that were granted at the end of March, 2015.
Cash-settled share-based retention awards, which are included in SG&A costs, are measured at fair value, and in the 2015-quarter, the related compensation expense recognized by PHX Energy decreased to a recovery of $0.7 million as compared to a recovery of $0.3 million in the 2014-quarter. The decrease is primarily due to the re-valuation of the retention awards based on the decrease in PHX Energy's stock price from $5.48 as at June 30, 2015 to $2.85 as at September 30, 2015.
| |
| (Stated in thousands of dollars) |
| |
| |
Three-month periods ended September 30, |
Nine-month periods ended September 30, |
| |
2015 |
2014 |
%
Change |
2015 |
2014 |
%
Change |
| Provision for settlement of litigations |
5,555 |
- |
n.m. |
6,533 |
- |
n.m. |
| |
|
|
|
|
|
|
In September, 2015, Phoenix USA and the parties to the collective and class actions in the US entered into a settlement agreement wherein the parties have agreed for the full and final release and dismissal of all claims and allegations made in the collective and class actions, by the establishment of a US$5.0 million (equivalent to CDN$6.5 million) settlement fund. As a result, an additional $5.6 million was recognized as provision for the settlement of litigations in the three-month period ended September 30, 2015.
| |
|
| (Stated in thousands of dollars) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
2014 |
%
Change |
|
2015 |
2014 |
%
Change |
|
| Research & development expense |
615 |
915 |
(33 |
) |
1,789 |
2,413 |
(26 |
) |
| |
|
|
|
|
|
|
|
|
Research and development ("R&D") expenditures charged to net earnings during the three-month periods ended September 30, 2015 and 2014 were $0.6 million and $0.9 million, respectively. During both the 2015 and 2014-quarters, none of the R&D expenditures were capitalized as development costs.
For the nine-month period ended September 30, 2015, R&D expenditures incurred decreased by 26 percent to $1.8 million from $2.4 million in the corresponding 2014-period.
The decrease in R&D expenditures in both 2015-periods is primarily due to the reduction of personnel related costs in the R&D department and the receipt of $0.3 million in scientific research and experimental development tax credits in the second quarter of 2015.
| |
|
| (Stated in thousands of dollars) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
2014 |
%
Change |
|
2015 |
2014 |
%
Change |
|
| Finance expense |
698 |
1,033 |
(32 |
) |
2,830 |
2,925 |
(3 |
) |
| |
|
|
|
|
|
|
|
|
Finance expenses relate to interest charges on the Corporation's long-term and short-term bank facilities. As expected, finance charges decreased to $0.7 million in the third quarter of 2015 from $1.0 million in the 2014-quarter, and in the nine-month period ended September 30, 2015 decreased to $2.8 million from $2.9 million in the 2014-period. The decrease in both periods was primarily due to the lower amount of borrowings outstanding during the three and nine-month periods ended September 30, 2015 that resulted from significant repayments made in the 2015-periods.
| |
| (Stated in thousands of dollars) |
| |
| |
Three-month periods ended September 30, |
Nine-month periods ended September 30, |
| |
2015 |
2014 |
%
Change |
2015 |
2014 |
%
Change |
| Impairment losses on goodwill and intangible assets |
13,824 |
- |
n.m. |
13,824 |
- |
n.m. |
| |
|
|
|
|
|
|
In the third quarter of 2015, the Corporation determined that the continuation of the industry downturn and the delay in the expected recovery of the oil prices were indicators of impairment as they would impact future activity levels. As such an impairment test was performed on the Corporation's Canadian and Stream CGUs. Based on the results of the impairment tests, an impairment loss of $13.8 million related to the Stream CGU was recognized in the three-month period ended September 30, 2015 (2014 - nil). Of the impairment loss, $7.3 was allocated to goodwill and $6.5 million was allocated to intangible assets, which are comprised of $5.8 million relating to an old version of the EDR technology and $0.7 million relating to a customer relationship.
| |
|
| (Stated in thousands of dollars) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
|
2014 |
|
2015 |
|
2014 |
|
| Loss (Gain) on disposition of drilling equipment |
4,280 |
|
(607 |
) |
3,673 |
|
(3,870 |
) |
| Foreign exchange losses (gains) |
(638 |
) |
(858 |
) |
(807 |
) |
(466 |
) |
| Provision for bad debts |
- |
|
278 |
|
38 |
|
1,013 |
|
| Other expenses (income) |
3,642 |
|
(1,187 |
) |
2,904 |
|
(3,323 |
) |
| |
|
|
|
|
|
|
|
|
For the three and nine-month periods ended September 30, 2015, other expenses is primarily comprised of losses on the disposition of drilling equipment of $4.3 million (2014 - gain of $0.6 million) and $3.7 million (2014 - gain of $3.9 million), respectively. Losses typically result from any asset retirements that were made before the end of the equipment's useful life and self-insured down hole equipment losses. 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. In the 2015-periods, the loss on disposition of drilling equipment resulted primarily from decommissioning a number of performance drilling motors for the purpose of utilizing the spare parts to service the remainder of the performance drilling motor fleet.
Offsetting other expenses for the three and nine-month periods ended September 30, 2015 is foreign exchange gains of $0.6 million (2014 - $0.9 million) and $0.8 million (2014 - $0.5 million), respectively, which resulted mainly from the revaluation of Canadian-denominated intercompany payables in the US. The US dollar strengthened against the Canadian dollar during the 2015-periods.
| |
| (Stated in thousands of dollars, except percentages) |
| |
| |
Three-month periods ended September 30, |
Nine-month periods ended September 30, |
| |
2015 |
|
2014 |
2015 |
|
2014 |
| Provision for (Recovery of) income taxes |
(7,123 |
) |
3,286 |
(10,348 |
) |
7,792 |
| Effective tax rates |
23% |
|
20% |
21% |
|
27% |
| |
|
|
|
|
|
|
The recovery of income taxes for the three-month period ended September 30, 2015 was $7.1 million as compared to a provision for income taxes of $3.3 million in the 2014-quarter. For the nine-month period ended September 30, 2015, the recovery of income taxes was $10.3 million as compared to a provision for income taxes of $7.8 million in the corresponding 2014-period. The Government of Alberta increased the corporate income tax rate from 10 percent to 12 percent, resulting in a blended corporate tax rate of 11 percent for the year ended December 31, 2015. This was substantively enacted in June, 2015. As a result, the expected combined Canadian federal and provincial tax rate for 2015 was increased to 26 percent. The effective tax rates in the 2015-periods were lower than the expected rates primarily due to the non-deductibility of the goodwill impairment for tax purposes.
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, |
|
| |
2015 |
|
2014 |
%
Change |
|
2015 |
|
2014 |
%
Change |
|
| Revenue |
19,499 |
|
51,111 |
(62 |
) |
69,319 |
|
131,359 |
(47 |
) |
| Reportable segment profit (loss) before tax |
(19,880 |
) |
11,432 |
n.m. |
|
(29,361 |
) |
14,537 |
n.m. |
|
| |
|
|
|
|
|
|
|
|
|
|
PHX Energy's Canadian revenue for the three-month period ended September 30, 2015 decreased by 62 percent to $19.5 million from $51.1 million in the corresponding 2014-period. The decrease was generally due to weak industry activity and lower day rates realized in the 2015-quarter. In the third quarter of 2015, the Canadian segment reported 2,075 operating days, a 55 percent decrease from the 4,606 days in the 2014-period. In comparison, total industry horizontal and directional drilling activity, as measured by drilling days, declined by 49 percent in the 2015-quarter to 16,113 days from 31,828 days in the 2014-quarter. (Source: Daily Oil Bulletin) Average day rates also continued to decline and in the 2015-quarter they decreased by 15 percent to $9,067 from $10,698 in the 2014-quarter, excluding Stream revenue of $0.7 million.
Despite of these lower activity levels, the Canadian division maintained its healthy market share and a well-diversified client base. During the 2015-quarter, the Corporation's activity was weighted towards oil well drilling, 85 percent of wells drilled, and PHX Energy was active in the Montney, Wilrich, Bakken, Shaunavon, and Viking areas.
For the nine-month period of 2015, PHX Energy's Canadian revenue decreased by 47 percent to $69.3 million from $131.4 million in the comparable 2014-period. The Corporation's operating days decreased by 41 percent to 6,843 days in the 2015 nine-month period from 11,661 days in the 2014-period. In comparison, the number of horizontal and directional drilling days realized in the Canadian industry for the nine-month period ended September 30, 2015 decreased by 44 percent to 49,356 days as compared to 87,707 days in the nine-month period of 2014. (Sources: Daily Oil Bulletin)
The Canadian operations' reportable segment loss before tax for the third quarter of 2015 was $19.9 million as compared to a reportable segment profit before tax of $11.4 million in the 2014-quarter. For the nine-month period ended September 30, 2015, reportable segment loss before tax was $29.4 million as compared to a reportable segment profit before tax of $14.5 million in the 2014-period.
Included in the Canadian segment's losses in the three and nine-month period ended September 30, 2015 were losses of $15.3 million (2014 - $1.9 million) and $20.1 million (2014 - $4.5 million), respectively, from the Stream division. The Stream division's losses in the 2015-periods primarily resulted from the recognition of $13.8 million in impairment losses on goodwill and intangible assets. In addition, nil and $1.1 million in severance costs were incurred in the Stream division for the three and nine-month periods of 2015, respectively.
During the 2015-periods, the Canadian segment's profitability was also negatively affected by a change in the estimate of the residual values of its drilling equipment, which resulted in $4.8 million of additional depreciation expense.
United States
| |
|
| (Stated in thousands of dollars) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
|
2014 |
%
Change |
|
2015 |
|
2014 |
%
Change |
|
| Revenue |
42,521 |
|
75,985 |
(44 |
) |
142,498 |
|
199,294 |
(28 |
) |
| Reportable segment profit (loss) before tax |
(1,797 |
) |
5,319 |
(134 |
) |
(7,754 |
) |
16,930 |
(146 |
) |
| |
|
|
|
|
|
|
|
|
|
|
In the third quarter of 2015, revenue from PHX Energy's US operations decreased by 44 percent to $42.5 million from $76.0 million in the 2014-quarter. The decrease mainly resulted from the significantly reduced industry rig count. In the third quarter of 2015, the number of horizontal and directional rigs running per day decreased by 52 percent from an average of 1,531 horizontal and directional rigs running per day during the 2014-quarter to 742 in the 2015-quarter. (Source: Baker Hughes) In comparison, the Corporation's US activity levels also weakened as operating days decreased by 47 percent from 4,956 days in the 2014-quarter to 2,612 days in the 2015-quarter. Generally due to the positive impact of a stronger US dollar, average day rates, excluding the motor rental division in Midland, Texas and the Rocky Mountain region, increased to $15,725 in the 2015-quarter compared to $14,476 in the 2014-period. Excluding the effects of foreign exchange, the average day rates actually decreased by 9 percent to $13,099 in the 2015-quarter, primarily as a result of the competitive pricing environment.
Horizontal and directional drilling represented 86 percent of the average number of rigs running on a daily basis in the third quarter of 2015 which was 6 percent greater than the percentage in 2014. For the three-month period ended September 30, 2015, oil well drilling, as measured by wells drilled and excluding the motor rental and gyro surveying divisions, increased to 65 percent of PHX Energy's US activity. During the third quarter of 2015, Phoenix USA remained active in the Permian, Eagle Ford, Bakken, Mississippian/Woodford, Marcellus, Niobrara and Utica basins and market share increased slightly in all US regions.
For the nine-month period ended September 30, 2015, US revenue decreased by 28 percent to $142.5 million from $199.3 million in the comparable 2014-period. US operating days in the 2015 nine-month period decreased by 32 percent to 9,042 days from 13,241 days in the 2014-period. In comparison, US industry activity, as measured by the average number of horizontal and directional rigs running on a daily basis, decreased by 38 percent in the nine-month period of 2015 to 907 rigs from 1,461 rigs in the comparable 2014-period. (Source: Baker Hughes)
Reportable segment loss before tax for the three-month period ended September 30, 2015 was $1.8 million compared to a reportable segment profit before tax of $5.3 million (7 percent of revenue) in the 2014-quarter. For the nine-month period ended September 30, 2015, reportable segment loss before tax was $7.8 million compared to a reportable segment profit before tax of $16.9 million (8 percent of revenue) in the comparative 2014-period. As in the previous 2015-quarters, decreased profitability in the 2015-periods was largely the result of weaker activity levels and lower average day rates.
International
| |
|
| (Stated in thousands of dollars, except percentages) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
2015 |
2014 |
%
Change |
|
2015 |
2014 |
%
Change |
|
| Revenue |
6,207 |
11,875 |
(48 |
) |
18,825 |
37,933 |
(50 |
) |
| Reportable segment profit before tax |
797 |
2,586 |
(69 |
) |
3,554 |
7,876 |
(55 |
) |
| Reportable segment profit before tax as a percentage of revenue |
13% |
22% |
|
|
19% |
21% |
|
|
| |
|
|
|
|
|
|
|
|
For the three-month period ended September 30, 2015, the Corporation's international revenue decreased by 48 percent to $6.2 million from the $11.9 million generated in the 2014-period. International operating days decreased by 22 percent from 901 days in the 2014-quarter to 700 days in the 2015-quarter. The Corporation generated 9 percent of its consolidated revenue from its international operations in the 2015-quarter, which is the same percentage as in the 2014-quarter.
For the nine-month period ended September 30, 2015, revenue decreased by 50 percent to $18.8 million from $37.9 million in the comparable 2014-period. International operating days in the nine-month period of 2015 were 2,135 days, 25 percent lower compared to the 2,828 days generated in the 2014-period.
The Albanian division remained active on two rigs for the majority of the quarter with occasional services delivered to a local operator. For the three-month period ended September 30, 2015 activity decreased 60 percent as compared to the corresponding 2014-quarter. Despite the steep decline in activity and additional pricing concessions that took place in the 2015-quarter, the Albanian operations remained profitable. Efforts to reduce the cost base have been successful and maximizing the use of local staff where possible has also had a positive impact to the financial results of the operation. Initiatives to optimize equipment through collaborative efforts with clients have also helped deliver improved operational and financial performance.
PHX Energy's Russian operations continued to benefit from its long term initiatives to diversify its client base and in the third quarter of 2015, the division reported a 26 percent increase in activity compared to the 2014-period, despite low commodity prices and the prevailing economic and geopolitical climate in Russia. As a result of increased activity, profitability for this division also improved, despite the negative impact of the further devaluation of the Russian Ruble against the Canadian dollar.
Reportable segment profit from international operations for the three-month period ended September 30, 2015 was $0.8 million (13 percent of revenue), which is 69 percent lower than the $2.6 million (22 percent of revenue) generated in the corresponding 2014-period. Reportable segment profit for the nine-month period ended September 30, 2015 was $3.6 million (19 percent of revenue) as compared to $7.9 million (21 percent of revenue) in the 2014-period; a 55 percent decrease. The decrease in the international operations' profitability in both 2015-periods was mainly due to weaker activity levels in Albania.
Investing Activities
Net cash used in investing activities for the three-month period ended September 30, 2015 was $8.1 million as compared to $16.0 million in 2014. In the third quarter of 2015, PHX Energy added $1.7 million, net, in capital equipment (2014 - $27.9 million). The capital equipment amounts are net of proceeds from the involuntary disposal of drilling equipment in well bores of $0.7 million (2014 - $3.3 million). The quarterly 2015 expenditures included:
- $1.6 million in MWD systems and spare components;
- $0.3 million in machinery and equipment;
- $0.3 million in down hole performance drilling motors; and
- $0.1 million in leasehold improvements.
The capital expenditure program undertaken in the period was financed generally from working capital.
During the 2015-quarter, the Corporation spent $5.7 million in intangible assets, $5.5 million of which related to a license agreement and $0.2 million related to development costs. The change in non-cash working capital balances of $0.7 million (use of cash) for the three-month period ended September 30, 2015, relates to the net change in the Corporation's trade payables that are associated with the acquisition of capital assets. This compares to $12.5 million (source of cash) for the three-month period ended September 30, 2014.
Financing Activities
The Corporation reported cash flows used in financing activities of $3.2 million in the three-month period ended September 30, 2015 as compared to cash flows from financing activities of $18.1 million in the 2014-period. In the 2015-quarter:
- through its DRIP program, the Corporation received cash proceeds of $80,000 from reinvested dividends to acquire 20,781 common shares of the Corporation;
- an additional $114,000 was incurred in transaction costs that related to the equity financing in June 30, 2015;
- the Corporation paid dividends of $2.2 million to shareholders, or $0.05 per share; and
- the Corporation made aggregate net repayments of $1.0 million on its operating and syndicated facilities.
Capital Resources
As of September 30, 2015, the Corporation had $70.0 million drawn on its syndicated facility, $0.3 million drawn on its operating facility, and nil drawn on its US operating facility.
On October 16, 2015, the Corporation amended its credit agreement with its syndicate of lenders. The key amendments reflected the following revisions to PHX Energy's financial and negative covenants under its credit facilities (defined terms have the meanings ascribed thereto in the credit agreement, a copy of which can be found under PHX Energy's profile on SEDAR at www.sedar.com):
- The ratio of debt to covenant EBITDA shall not exceed 5.0x for the quarters ending December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016, shall not exceed 4.0x for the quarter ending December 31, 2016 and shall not exceed 3.0x for the quarter ending March 31, 2017, all calculated on a four quarter rolling basis.
- For the purposes of the calculation of the covenant EBITDA during the period from the quarter ended March 31, 2015 to the quarter ending March 31, 2016, PHX Energy shall be permitted to add back actual severance costs paid up to a maximum of CDN$5.0 million and settlement amounts to be paid (and provisions made in respect thereof) by the Corporation in respect of the US litigations to a maximum aggregate of CDN$6.5 million.
- The Corporation's negative covenant, which limits its annual dividends based on the amount of its yearly distributable cash flow, shall not apply to the financial year ending December 31, 2015. In addition, during the covenant relief period through to December 31, 2016, there will be no increases permitted in the rate of dividends payable by the Corporation.
- The maximum principal amounts available to the Corporation under each of the Syndicated Credit Facility and the US Operating Facility were reduced from CDN$160 million to CDN$90 million and US$25 million to US$2.5 million, respectively.
In accordance with the amendments, effective September 30, 2015, EBITDA under the credit agreement (referred above as "covenant EBITDA"), was calculated as 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, and provision for settlement of litigations, subject to the restrictions provided in the amended credit agreement.
As at September 30, 2015, the Corporation was in compliance with all 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. In order to preserve cash flows, the 2015 capital budget has been decreased from the previously announced $28.3 million to $18.5 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 2015, 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 very challenging market conditions that have persisted in the drilling industry for the past year continued through the third quarter of 2015. Despite this difficult environment PHX Energy generated positive adjusted EBITDA in the third quarter of 2015, an accomplishment that required the Corporation to diligently implement many strategic cost initiatives throughout the 2015-year. Although many of the decisions were very difficult to make, the improvement in profitability in the third quarter as compared to the prior two quarters of the year demonstrates that the proactive measures taken were necessary.
Industry forecasts for North American activity show continued declines in oil and gas operating companies' capital expenditure programs for at least the first half of 2016. With limited access to capital markets and lower commodity prices persisting, cash flows are slowing for these operators and as a result they continue to decrease their drilling budgets, driving the active rig counts down in the drilling regions PHX Energy operates. This market contraction has caused pricing pressures to mount significantly.
Despite the combination of North American rig counts being approximately 50 percent lower than in 2014 and the extremely competitive environment, both PHX Energy's US and Canadian operations have maintained market share in the third quarter of 2015. In some areas the Corporation believes that market share will increase in future quarters as a result of the superior performance and quality of service PHX Energy provides.
In Albania, there are similar challenges to those in North America, and in the Russian market although the industry has remained relatively robust, the Corporation has been impacted by the effects of a dropping Russian Ruble. Nevertheless, international operations continue to contribute positive earnings to the Corporation's income.
The severity of the drop in the price of oil and the resulting collapse in the active drilling rig count has hit very hard. PHX Energy has reacted quickly and will continue to make adjustments accordingly to maintain its stable financial position. Today, the Corporation believes profitability can be sustained within the current market conditions and PHX Energy is focused on ensuring it is in a position to capture more market share at improved margins when the upswing takes hold.
Michael Buker, President
November 4, 2015
Non-GAAP Measures
1) Adjusted EBITDA
Adjusted EBITDA, defined as earnings before finance expense, income taxes, depreciation and amortization, gain or loss on disposition of drilling equipment, impairment losses on goodwill and intangible assets, provisions for the settlement of litigations, and severance costs, 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, |
|
| |
2015 |
|
2014 |
|
2015 |
|
2014 |
|
| Net earnings (loss) |
(24,515 |
) |
13,024 |
|
(38,707 |
) |
20,775 |
|
| Add: |
|
|
|
|
|
|
|
|
| |
Depreciation and amortization |
14,903 |
|
8,207 |
|
33,829 |
|
23,138 |
|
| |
Provision for (Recovery of) income taxes |
(7,123 |
) |
3,287 |
|
(10,348 |
) |
7,792 |
|
| |
Finance expense |
697 |
|
1,033 |
|
2,830 |
|
2,925 |
|
| |
Loss (Gain) on disposition of drilling equipment |
4,280 |
|
(607 |
) |
3,673 |
|
(3,870 |
) |
| |
Impairment losses on goodwill and intangible assets |
13,823 |
|
- |
|
13,824 |
|
- |
|
| |
Provision for settlement of litigations |
5,555 |
|
- |
|
6,533 |
|
|
|
| |
Severance costs |
1,286 |
|
945 |
|
5,424 |
|
2,437 |
|
| Adjusted EBITDA as reported |
8,906 |
|
25,889 |
|
17,058 |
|
53,197 |
|
| |
|
|
|
|
|
|
|
|
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, |
| |
2015 |
|
2014 |
|
2015 |
|
2014 |
| Cash flows from operating activities |
10,780 |
|
(1,735 |
) |
42,950 |
|
17,664 |
| Add (deduct): |
|
|
|
|
|
|
|
| |
Changes in non-cash working capital |
(9,994 |
) |
26,759 |
|
(42,750 |
) |
31,877 |
| |
Interest paid |
575 |
|
1,152 |
|
2,339 |
|
2,780 |
| |
Income taxes received |
(684 |
) |
526 |
|
1,778 |
|
1,399 |
| Funds from operations |
677 |
|
26,702 |
|
4,317 |
|
53,720 |
| |
|
|
|
|
|
|
|
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, and provision for settlement of litigations, subject to the restrictions provided in the amended loan agreement.
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, Albania, and Russia. 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; Fort Worth, Texas; Midland, Texas; Bellaire, Ohio; Pittsburgh, Pennsylvania; and Oklahoma City, Oklahoma. Internationally, PHX Energy has sales offices and service facilities in Albania and Russia, 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.
The common shares of PHX Energy trade on the Toronto Stock Exchange under the symbol PHX.
| |
|
| Consolidated Statements of Financial Position |
|
| (unaudited) |
|
| |
|
| |
September 30,
2015 |
|
December 31,
2014 |
|
| ASSETS |
|
|
|
|
|
|
| Current assets: |
|
|
|
|
|
|
| |
Cash and cash equivalents |
$ |
2,871,322 |
|
$ |
3,018,445 |
|
| |
Trade and other receivables |
|
55,693,692 |
|
|
122,272,125 |
|
| |
Inventories |
|
32,642,280 |
|
|
32,423,158 |
|
| |
Current tax receivables |
|
4,580,944 |
|
|
- |
|
| |
Prepaid expenses |
|
3,450,291 |
|
|
4,505,300 |
|
| |
Total current assets |
|
99,238,529 |
|
|
162,219,028 |
|
| Non-current assets: |
|
|
|
|
|
|
| |
Drilling and other equipment |
|
179,123,119 |
|
|
190,891,854 |
|
| |
Goodwill |
|
8,876,351 |
|
|
16,229,756 |
|
| |
Intangible assets |
|
25,830,658 |
|
|
25,581,960 |
|
| |
Deferred tax assets |
|
180,832 |
|
|
- |
|
| |
Total non-current assets |
|
214,010,960 |
|
|
232,703,570 |
|
| Total assets |
$ |
313,249,489 |
|
$ |
394,922,598 |
|
| LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
| Current liabilities: |
|
|
|
|
|
|
| |
Operating facility |
$ |
302,930 |
|
$ |
5,503,176 |
|
| |
Trade and other payables |
|
32,456,428 |
|
|
72,203,463 |
|
| |
Provisions |
|
6,533,426 |
|
|
- |
|
| |
Dividends payable |
|
137,167 |
|
|
2,466,649 |
|
| |
Current tax liabilities |
|
- |
|
|
832,352 |
|
| |
Current portion of finance leases |
|
- |
|
|
238,911 |
|
| |
Total current liabilities |
|
39,429,951 |
|
|
81,244,551 |
|
| Non-current liabilities: |
|
|
|
|
|
|
| |
Loans and borrowings |
|
70,000,000 |
|
|
104,280,800 |
|
| |
Deferred tax liabilities |
|
- |
|
|
7,602,868 |
|
| |
Deferred income |
|
1,733,336 |
|
|
1,833,335 |
|
| |
Total non-current liabilities |
|
71,733,336 |
|
|
113,717,003 |
|
| Equity: |
|
|
|
|
|
|
| |
Share capital |
|
213,553,012 |
|
|
178,650,340 |
|
| |
Contributed surplus |
|
5,331,779 |
|
|
4,513,265 |
|
| |
Retained earnings |
|
(32,196,409 |
) |
|
16,861,918 |
|
| |
Accumulated other comprehensive income |
|
15,397,820 |
|
|
(64,479 |
) |
| |
Total equity |
|
202,086,202 |
|
|
199,961,044 |
|
| |
|
|
|
|
|
|
|
| Total liabilities and equity |
$ |
313,249,489 |
|
$ |
394,922,598 |
|
| |
|
|
|
|
|
|
| |
|
| Consolidated Statements of Comprehensive Income |
|
| (unaudited) |
|
| |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
| Revenue |
$ |
68,227,342 |
|
$ |
138,971,376 |
|
$ |
230,641,748 |
|
$ |
368,586,036 |
|
| Direct costs |
|
66,640,879 |
|
|
107,926,830 |
|
|
222,198,203 |
|
|
294,903,700 |
|
| Gross profit |
|
1,586,463 |
|
|
31,044,546 |
|
|
8,443,545 |
|
|
73,682,336 |
|
| Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Selling, general and administrative expenses |
|
8,891,741 |
|
|
13,972,945 |
|
|
29,619,318 |
|
|
43,100,832 |
|
| |
Provision for the settlement of litigations |
|
5,555,453 |
|
|
- |
|
|
6,533,426 |
|
|
- |
|
| |
Research and development expenses |
|
614,745 |
|
|
915,228 |
|
|
1,789,359 |
|
|
2,412,698 |
|
| |
Finance expense |
|
697,513 |
|
|
1,032,864 |
|
|
2,829,747 |
|
|
2,924,905 |
|
| |
Impairment losses on goodwill and intangible assets |
|
13,823,514 |
|
|
- |
|
|
13,823,514 |
|
|
- |
|
| |
Other expenses (income) |
|
3,642,073 |
|
|
(1,187,049 |
) |
|
2,903,859 |
|
|
(3,323,134 |
) |
| |
|
33,225,039 |
|
|
14,733,988 |
|
|
57,499,223 |
|
|
45,115,301 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Earnings (Loss) before income taxes |
|
(31,638,576 |
) |
|
16,310,558 |
|
|
(49,055,678 |
) |
|
28,567,035 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Provision for (Recovery of) income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Current |
|
(2,541,157 |
) |
|
8,463,268 |
|
|
(1,562,740 |
) |
|
11,049,447 |
|
| |
Deferred |
|
(4,581,993 |
) |
|
(5,176,828 |
) |
|
(8,785,661 |
) |
|
(3,257,212 |
) |
| |
|
(7,123,150 |
) |
|
3,286,440 |
|
|
(10,348,401 |
) |
|
7,792,235 |
|
| Net earnings (loss) |
|
(24,515,426 |
) |
|
13,024,118 |
|
|
(38,707,277 |
) |
|
20,774,800 |
|
| Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Foreign currency translation |
|
5,767,432 |
|
|
585,625 |
|
|
15,462,299 |
|
|
(92,270 |
) |
| Total comprehensive income (loss) for the period |
$ |
(18,747,994 |
) |
$ |
13,609,743 |
|
$ |
(23,244,978 |
) |
$ |
20,682,530 |
|
| Earnings (Loss) per share - basic |
$ |
(0.59 |
) |
$ |
0.37 |
|
$ |
(1.03 |
) |
$ |
0.60 |
|
| Earnings (Loss) per share - diluted |
$ |
(0.59 |
) |
$ |
0.37 |
|
$ |
(1.03 |
) |
$ |
0.59 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| Consolidated Statements of Cash Flows |
|
| (unaudited) |
|
| |
Three-month periods ended September 30, |
|
Nine-month periods ended September 30, |
|
| |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
| Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| Net earnings (loss) |
$ |
(24,515,426 |
) |
$ |
13,024,118 |
|
$ |
(38,707,277 |
) |
$ |
20,774,800 |
|
| Adjustments for: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depreciation and amortization |
|
14,902,807 |
|
|
8,207,226 |
|
|
33,829,413 |
|
|
23,138,397 |
|
| |
Provision for (Recovery of) income taxes |
|
(7,123,150 |
) |
|
3,286,440 |
|
|
(10,348,401 |
) |
|
7,792,235 |
|
| |
Unrealized foreign exchange loss (gain) |
|
(661,676 |
) |
|
1,306,465 |
|
|
(1,540,156 |
) |
|
1,426,506 |
|
| |
Loss (Gain) on disposition of drilling equipment |
|
4,279,862 |
|
|
(606,813 |
) |
|
3,672,988 |
|
|
(3,870,138 |
) |
| |
Impairment loss on goodwill and intangible assets |
|
13,823,514 |
|
|
- |
|
|
13,823,514 |
|
|
- |
|
| |
Equity-settled share-based payments |
|
285,279 |
|
|
207,002 |
|
|
818,514 |
|
|
621,086 |
|
| |
Finance expense |
|
697,513 |
|
|
1,032,864 |
|
|
2,829,747 |
|
|
2,924,905 |
|
| |
Amortization of deferred income |
|
(33,333 |
) |
|
(33,333 |
) |
|
(99,999 |
) |
|
(99,999 |
) |
| |
Provision for bad debts |
|
- |
|
|
277,608 |
|
|
38,407 |
|
|
1,012,706 |
|
| |
Other non-cash charges |
|
(977,973 |
) |
|
- |
|
|
- |
|
|
- |
|
| |
Change in non-cash working capital |
|
9,994,349 |
|
|
(26,758,743 |
) |
|
42,750,091 |
|
|
(31,876,958 |
) |
| Cash generated from (used in) operating activities |
|
10,671,766 |
|
|
(57,166 |
) |
|
47,066,841 |
|
|
21,843,540 |
|
| Interest paid |
|
(575,969 |
) |
|
(1,152,572 |
) |
|
(2,339,511 |
) |
|
(2,780,046 |
) |
| Income taxes received (paid) |
|
684,449 |
|
|
(525,625 |
) |
|
(1,777,689 |
) |
|
(1,399,058 |
) |
| Net cash from (used in) operating activities |
|
10,780,246 |
|
|
(1,735,363 |
) |
|
42,949,641 |
|
|
17,664,436 |
|
| Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Proceeds on disposition of drilling equipment |
|
653,040 |
|
|
3,343,466 |
|
|
3,322,993 |
|
|
10,748,952 |
|
| |
Acquisition of drilling and other equipment |
|
(2,338,258 |
) |
|
(31,236,057 |
) |
|
(17,155,565 |
) |
|
(55,761,391 |
) |
| |
Acquisition of intangible assets |
|
(5,676,534 |
) |
|
(646,611 |
) |
|
(7,862,039 |
) |
|
(8,531,427 |
) |
| |
Change in non-cash working capital |
|
(723,817 |
) |
|
12,539,486 |
|
|
(3,459,060 |
) |
|
8,376,881 |
|
| Net cash used in investing activities |
|
(8,085,569 |
) |
|
(15,999,716 |
) |
|
(25,153,671 |
) |
|
(45,166,985 |
) |
| Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Proceeds from (Payments for) issuance of share capital (net) |
|
(34,018 |
) |
|
1,756,371 |
|
|
34,311,343 |
|
|
9,451,805 |
|
| |
Dividends paid to shareholders |
|
(2,181,391 |
) |
|
(7,355,760 |
) |
|
(12,680,532 |
) |
|
(21,807,987 |
) |
| |
Proceeds from (Repayment of) loans and borrowings |
|
3,000,000 |
|
|
17,000,000 |
|
|
(34,280,800 |
) |
|
37,000,000 |
|
| |
Payments under finance leases |
|
(5,478 |
) |
|
(42,477 |
) |
|
(92,858 |
) |
|
(143,556 |
) |
| |
Proceeds from (Repayment of) operating facility |
|
(4,001,344 |
) |
|
6,783,087 |
|
|
(5,200,246 |
) |
|
6,783,087 |
|
| Net cash from (used in) financing activities |
|
(3,222,231 |
) |
|
18,141,221 |
|
|
(17,943,093 |
) |
|
31,283,349 |
|
| Net increase (decrease) in cash and cash equivalents |
|
(527,554 |
) |
|
406,142 |
|
|
(147,123 |
) |
|
3,780,800 |
|
| Cash and cash equivalents, beginning of period |
|
3,398,876 |
|
|
9,038,538 |
|
|
3,018,445 |
|
|
5,663,880 |
|
| Cash and cash equivalents, end of period |
$ |
2,871,322 |
|
$ |
9,444,680 |
|
$ |
2,871,322 |
|
$ |
9,444,680 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|