CALGARY, ALBERTA--(Marketwired - Feb. 22, 2017) -
Financial Results
In 2016, PHX Energy (TSX:PHX) continued to persevere through one of the worst downturns in the industry's history as low
commodity prices prevailed for much of the 2016-year. Like many other service providers in the oil and natural gas industry, the
Corporation was deeply impacted by customer pricing pressures and record low drilling activity which caused revenue to fall below
2015 results. As revenues declined, PHX Energy continued its mandate to protect its financial position and align its cost
structure with activity levels where possible.
The Corporation generated consolidated revenue of $148.4 million during the year ended December 31, 2016, which is 48 percent
lower than the $286.8 million generated in the comparable 2015-period. The decline in revenue resulted from a 24 percent decrease
in average consolidated day rates from $12,184 in 2015 to $9,277 in 2016 and a 32 percent decrease in operating days from 22,784
days in the 2015-year to 15,536 days in 2016-year.
For the year ended December 31, 2016, PHX Energy realized adjusted EBITDA of $5.0 million (3 percent of revenue), which is 79
percent lower than the $23.6 million (8 percent of revenue) reported in the comparable 2015-period. Adjusted EBITDA as a
percentage of revenue decreased to 7 percent in the fourth quarter of 2016 from 17 percent in the comparable 2015-quarter.
For the year ended December 31, 2016, PHX Energy reported a net loss of $46.5 million compared to losses of $42.5 million
incurred in the 2015-year. The 2016 net loss includes a pre-tax cash-settled share-based payment expense of $4.1 million (2015 -
$0.3 million recovery), provisions for inventory of $3.2 million (2015 - $0.5 million), a provision for onerous contracts of $2.3
million (2015 - nil), severance costs of $2.1 million (2015 - $6.5 million) and an equity-settled share-based payment expense of
$1.5 million (2015 - $0.9 million). The net loss incurred in the 2015-year also included the following pre-tax charges: a
provision for the settlement of US litigations of $6.5 million, and a $13.8 million impairment loss on goodwill and intangible
assets.
As at December 31, 2016, PHX Energy had long-term debt of $29.0 million and working capital of $44.2 million.
Capital Spending
For the year ended December 31, 2016, the Corporation further reduced capital spending to $7.8 million, which represents a 57
percent decrease from the $18.0 million spent in 2015. As at December 31, 2016, $1.4 million of equipment was on order and is
expected to be received within the first half of 2017. Through the 2016-year the Corporation worked diligently to strengthen its
financial position and with signs that the industry is beginning to recover, PHX Energy anticipates that $25.0 million in capital
expenditures will be spent in the 2017-year. The Corporation believes this higher level of expenditures will allow PHX Energy to
capitalize on the forecasted industry growth by deploying new technologies recently developed.
Equity Financings
On June 28, 2016, PHX Energy closed a bought deal financing for aggregate proceeds of $23.3 million. An aggregate of 8,625,000
common shares of the Corporation were issued at a price of $2.70 per common share. Concurrent with the closing of the public
offering, certain directors, officers, employees and consultants of PHX Energy purchased a total of 495,407 common shares at a
price of $2.70 per share on a private placement basis. The gross proceeds from the public offering and concurrent private
placement totaled to approximately $24.6 million.
Subsequent to December 31, 2016, on February 2, 2017, the Corporation completed a bought-deal financing in which 7,187,500
common shares were issued at a price of $4.00 per common share for gross proceeds of $28.8 million. Concurrent with the closing
of the public offering, certain officers, directors and employees of PHX Energy and their associates participated in a private
placement purchasing an additional 500,000 common shares at a price of $4.00 per common share for gross proceeds to the
Corporation of $2.0 million. The gross proceeds from the public offering and concurrent private placement totaled approximately
$30.8 million
(Stated in thousands of dollars except per share amounts, percentages and shares outstanding)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
|
2015 |
|
% Change |
|
2016 |
|
2015 |
|
% Change |
|
| Operating Results |
(unaudited) |
|
(unaudited) |
|
|
|
|
|
|
|
|
|
| Revenue |
46,629 |
|
56,138 |
|
(17 |
) |
148,401 |
|
286,780 |
|
(48 |
) |
| Net loss |
(15,074 |
) |
(3,782 |
) |
n.m. |
|
(46,517 |
) |
(42,489 |
) |
9 |
|
| Loss per share - diluted |
(0.30 |
) |
(0.09 |
) |
n.m. |
|
(1.01 |
) |
(1.10 |
) |
(8 |
) |
| Adjusted EBITDA (1) |
3,182 |
|
9,662 |
|
(67 |
) |
5,048 |
|
23,631 |
|
(79 |
) |
| Adjusted EBITDA (1) per share - diluted |
0.06 |
|
0.23 |
|
(74 |
) |
0.11 |
|
0.61 |
|
(82 |
) |
| Adjusted EBITDA (1) as a percentage of revenue |
7 |
% |
17 |
% |
|
|
3 |
% |
8 |
% |
|
|
| Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash flows from operating activities |
359 |
|
18,353 |
|
(98 |
) |
5,091 |
|
61,303 |
|
(92 |
) |
| Funds from operations (1) |
2,060 |
|
9,529 |
|
(78 |
) |
559 |
|
13,846 |
|
(96 |
) |
| Funds from operations per share - diluted (1) |
0.04 |
|
0.23 |
|
(83 |
) |
0.01 |
|
0.36 |
|
(97 |
) |
| Dividends paid |
- |
|
137 |
|
(100 |
) |
416 |
|
12,818 |
|
(97 |
) |
| Dividends per share (2) |
- |
|
0.033 |
|
(100 |
) |
0.01 |
|
0.383 |
|
(97 |
) |
| Capital expenditures |
2,555 |
|
873 |
|
n.m. |
|
7,811 |
|
18,029 |
|
(57 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Financial Position, December 31, |
|
|
|
|
|
|
|
|
|
|
|
|
| Working capital |
|
|
|
|
|
|
44,230 |
|
61,041 |
|
(28 |
) |
| Long-term debt |
|
|
|
|
|
|
29,014 |
|
60,000 |
|
(52 |
) |
| Shareholders' equity |
|
|
|
|
|
|
178,387 |
|
200,938 |
|
(11 |
) |
| Common shares outstanding |
|
|
|
|
|
|
50,810,721 |
|
41,567,023 |
|
22 |
|
| (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. |
| n.m. |
- not meaningful |
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, delivery of
capital expenditure items, the projected capital expenditures budget and how this budget will be funded, anticipated growth
related to the deployment of new technologies, and projections related to Stream's future activity levels, profitability and
financial performance.
The above are stated under the headings: "Capital Spending", "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 document are expressly qualified by this cautionary statement. The Corporation does not undertake any
obligation to publicly update or revise any forward-looking statements or information, whether as a result of new information,
future events or otherwise, except as may be required by applicable securities laws.
Revenue
(Stated in thousands of dollars)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
2015 |
% Change |
|
2016 |
2015 |
% Change |
| Revenue |
46,629 |
56,138 |
(17 |
) |
|
148,401 |
286,780 |
(48 |
) |
| |
|
|
|
|
|
|
|
|
|
For the three-month period ended December 31, 2016, consolidated revenue decreased 17 percent to $46.6 million from $56.1
million in the 2015-quarter. The decrease in revenue in the fourth quarter of 2016 as compared to 2015 was primarily the result
of lower average consolidated day rates. For the three-month period ended December 31, 2016, average consolidated day rates,
excluding the US motor rental division and the Stream division, were $8,874 which is 23 percent lower than the 2015-period's day
rates of $11,508. The impact of the decreased consolidated average day rates was slightly offset by a 7 percent increase in PHX
Energy's activity. In the fourth quarter of 2016, the Corporation achieved 5,074 operating days up from 4,763 days recorded in
2015-quarter.
Overall rig counts in North America in the fourth quarter of 2016 remained at some of the lowest levels seen in the past 30
years, although they did show improvement over the trough in the second and third quarters of the year. In Canada, this recovery
did lead to a slight uptick in the rig count in the 2016-quarter as compared to the fourth quarter of 2015 whereas in the US, the
rig count was 20 percent lower quarter-over-quarter. Horizontal and directional drilling continues to dominate the market
representing 96 percent of the Canadian industry's operating days (2015 - 98 percent) and 88 percent of the US rigs running per
day (2015 - 86 percent). (Source: Daily Oil Bulletin and Baker Hughes)
For the year ended December 31, 2016, PHX Energy's consolidated revenue decreased to $148.4 million, a 48 percent reduction
from the $286.8 million generated in the 2015-period. US and international revenue, as a percentage of total consolidated
revenue, were 53 percent (2015 - 62 percent) and 11 percent (2015 - 8 percent), respectively. The decreased revenue for the year
ended December 31, 2016, as compared to 2015, was the result of lower consolidated day rates and drilling activity. Excluding the
US motor rental division and the Stream division, the average consolidated day rates for the 2016-year decreased by 24 percent to
$9,277 from $12,184 in 2015. The 15,536 consolidated operating days generated in the 2016-year were 32 percent lower than
the 22,784 days in 2015-year.
Operating Costs and Expenses
(Stated in thousands of dollars except percentages)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
|
2015 |
|
% Change |
|
|
2016 |
|
2015 |
|
% Change |
|
| Direct costs |
49,590 |
|
53,434 |
|
(7 |
) |
|
172,495 |
|
275,632 |
|
(37 |
) |
| Gross profit (loss) as a percentage of revenue |
(6 |
% ) |
5 |
% |
|
|
|
(16 |
% ) |
4 |
% |
|
|
| Depreciation & amortization (included in direct costs) |
10,886 |
|
14,454 |
|
(25 |
) |
|
49,752 |
|
48,283 |
|
3 |
|
| Gross profit as percentage of revenue excluding depreciation & amortization |
17 |
% |
31 |
% |
|
|
|
17 |
% |
21 |
% |
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
The Corporation continued to benefit from its cost reduction initiatives in the fourth quarter of 2016. Direct costs,
comprised of field and shop expenses and depreciation and amortization of the Corporation's equipment, decreased by 7 percent to
$49.6 million from $53.4 million in the 2015-quarter, while activity levels increased by 7 percent quarter-over-quarter. For the
three-month period ended December 31, 2016, gross loss as a percentage of revenue decreased to 6 percent as compared to a gross
profit as a percentage of revenue of 5 percent in the comparative 2015-period.
For the three-month period ended December 31, 2016, depreciation and amortization decreased by 25 percent to $10.9 million
from $14.5 million in the comparable 2015-period. This was a result of the lower capital spending throughout the 2016-year.
Excluding depreciation and amortization, gross profit as a percentage of revenue also decreased in the fourth quarter of 2016
over the 2015-quarter. The lower gross profit margins in the 2016-quarter mainly resulted from the decline in average
consolidated day rates that impacted the Corporation's revenues.
For the year ended December 31, 2016, direct costs decreased by 37 percent from $275.6 million in the 2015-year to $172.5
million. The decrease in direct costs is consistent with the 32 percent decline in the Corporation's year-over-year drilling
activity. For the year ended December 31, 2016, gross loss, as a percentage of revenue, decreased to 16 percent as compared to a
gross profit percentage of 4 percent in the comparative 2015-period. The gross loss margin in the 2016-year was mainly caused by
lower revenues as compared to the 2015-year.
Depreciation and amortization for the year ended December 31, 2016 increased by 3 percent over the comparable 2015-period. The
increased depreciation and amortization in the 2016-year was primarily the result of the change to the estimated residual value
of its drilling equipment, implemented in September of 2015. The effect of this change was a quarterly increase of $4.0 million
in depreciation and amortization expenses for the duration of the 2016-year. This increase was partially offset by reduced
depreciation that resulted from assets being fully depreciated and lower capital spending in 2016.
For the year ended December 31, 2016, gross profit as a percentage of revenue, excluding depreciation and amortization,
decreased to 17 percent as compared to 21 percent in 2015. The lower revenues that resulted from decreased average day rates and
consolidated operating days were the primary cause for the change in the gross profit percentage.
(Stated in thousands of dollars except percentages)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
|
2015 |
|
% Change |
|
2016 |
|
2015 |
|
% Change |
|
| Selling, general and administrative ("SG&A") costs |
9,914 |
|
7,664 |
|
29 |
|
31,628 |
|
37,283 |
|
(15 |
) |
| Equity-settled share-based payments (included in SG&A costs) |
165 |
|
58 |
|
n.m. |
|
1,542 |
|
877 |
|
76 |
|
| Cash-settled share-based payments (recoveries) (included in SG&A costs) |
1,585 |
|
(70 |
) |
n.m. |
|
4,094 |
|
(305 |
) |
n.m. |
|
| Provision for onerous contracts |
2,300 |
|
- |
|
100 |
|
2,300 |
|
- |
|
100 |
|
| SG&A costs excluding equity and cash-settled share- based payments and provision for onerous contracts
as a percentage of revenue |
13 |
% |
14 |
% |
|
|
16 |
% |
13 |
% |
|
|
SG&A costs for the three-month period ended December 31, 2016 were $9.9 million as compared to $7.7 million in the
2015-period. Included in SG&A costs for the 2016-period were equity-settled and cash-settled share-based payments of $0.2
million (2015 - $0.1 million) and $1.6 million (2015 - $0.1 million recovery), respectively. Additionally, SG&A costs for the
2016 three-month period include a $2.3 million provision for an onerous office lease contract (2015 - nil). Excluding the
share-based payment amounts and the provision for onerous contracts, SG&A costs as a percentage of consolidated revenue were
13 percent in the 2016 three-month period compared to 14 percent in the 2015-quarter.
For the year ended December 31, 2016, SG&A costs decreased by 15 percent to $31.6 million as compared to $37.3 million in
2015. For the 2016-year, excluding equity-settled and cash-settled share-based payments of $1.5 million (2015 - $0.9 million) and
$4.1 million (2015 - $0.3 million recovery), respectively, and a provision for onerous contracts of $2.3 million (2015 - nil),
SG&A costs as a percentage of consolidated revenue increased to 16 percent from 13 percent in the 2015-year. The increased
percentage was mainly caused by lower revenues in 2016 as a portion of these costs are fixed. Included in SG&A costs for the
year ended December 31, 2016 was severance costs of $0.4 million (2015 - $1.7 million).
The decrease in SG&A costs, in dollar terms, in both 2016-periods was mainly due to the Corporation's continued efforts to
reduce personnel related costs and overall spending in-line with weak drilling activity and average day rates.
Equity-settled share-based payments relate to the amortization of the fair values of issued options of the Corporation using
the Black-Scholes model. In the three-month period ended December 31, 2016, equity-settled share-based payments increased from
$0.1 million in the fourth quarter of 2015 to $0.2 million. For the year ended December 31, 2016, equity-settled share-based
payments in the amount of $1.5 million increased by 76 percent compared to the 2015-year amount of $0.9 million. The increased
expense in both 2016-periods was generally a result of recognizing compensation expenses related to the large option grant
completed in early 2016.
Cash-settled share-based retention awards are measured at fair value. In the fourth quarter of 2016, the related compensation
expense was $1.6 million as compared to a recovery of $0.1 million in the 2015-quarter. For the year ended December 31, 2016,
compensation expenses of $4.1 million were recognized as compared to a recovery of $0.3 million in 2015. The increase to the
compensation expense in both 2016-periods was mainly attributable to the re-valuation of the retention awards based on the
increase in PHX Energy's stock price from $2.36 as at December 31, 2015 and $3.75 as at September 30, 2016 to $4.22 as at
December 31, 2016.
(Stated in thousands of dollars)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
2015 |
% Change |
|
2016 |
2015 |
% Change |
| Research and development expense |
669 |
499 |
34 |
|
2,001 |
2,288 |
(13 |
) |
| |
|
|
|
|
|
|
|
|
During the three-month period ended December 31, 2016, PHX Energy recognized research and development ("R&D") expenses
amounting to $0.7 million compared to $0.5 million in the 2015-period. During both the 2016 and 2015-quarters, none of the
R&D expenditures were capitalized as development costs.
For the year ended December 31, 2016, the Corporation reduced R&D expenditures by 13 percent to $2.0 million (2015 - $2.3
million), none of which were capitalized as development costs (2015 - nil). The decrease in R&D expenditures in the 2016-year
is primarily due 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 December 31, |
|
Years ended December 31, |
| |
2016 |
2015 |
% Change |
|
2016 |
2015 |
% Change |
| Finance expense |
502 |
642 |
(22 |
) |
|
1,952 |
3,472 |
(44 |
) |
| |
|
|
|
|
|
|
|
|
|
Finance expenses relate to interest charges on the Corporation's long-term and short-term bank facilities. For both the
three-month period and year ended December 31, 2016, finance charges decreased over the comparable 2015-periods as the
Corporation continued to reduce its long-term and short-term borrowings.
(Stated in thousands of dollars)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
|
2015 |
|
|
2016 |
|
2015 |
|
| Net gain (loss) on disposition of drilling equipment |
(602 |
) |
(1,197 |
) |
|
115 |
|
(4,870 |
) |
| Foreign exchange gain (loss) |
(137 |
) |
466 |
|
|
30 |
|
1,273 |
|
| Provision for bad debts |
(173 |
) |
(180 |
) |
|
(369 |
) |
(218 |
) |
| Other expense |
(912 |
) |
(911 |
) |
|
(224 |
) |
(3,815 |
) |
| |
|
|
|
|
|
|
|
|
|
For the three-month period and year ended December 31, 2016, other expenses were primarily comprised of losses on the
disposition of drilling equipment of $0.6 million (2015 - $1.2 million) and a provision for bad debts of $0.2 million (2015 -
$0.2 million), respectively. Losses on the disposition of drilling equipment 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 2016-quarter, the loss on disposition of drilling equipment resulted primarily from
asset retirements. Provisions for bad debt in the 2016-year relate mainly to US accounts receivables.
(Stated in thousands of dollars except percentages)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
| |
2016 |
|
2015 |
|
|
2016 |
2015 |
| Provision for (Recovery of) income taxes |
116 |
|
(3,229 |
) |
|
(13,383 |
) |
(13,577 |
) |
| Effective tax rates |
(1 |
% ) |
46 |
% |
|
22 |
% |
24 |
% |
| |
|
|
|
|
|
|
|
|
|
The provision for income taxes for the three-month period ended December 31, 2016 was $0.1 million as compared to a recovery
of income taxes of $3.2 million in the 2015-period. For the year ended December 31, 2016, the recovery of income taxes was
$13.4 million as compared to $13.6 million in 2015. The expected combined Canadian federal and provincial tax rate for 2016
was 27 percent. The effective tax rate in the three-month period ended December 31, 2016 was lower than the expected rate
primarily due to the impact of an adjustment to the intercompany lease of drilling and other equipment between the Canadian and
US segments of $11.8 million. For the year ended December 31, 2016, the effective tax rate is lower than the expected rate
mainly as a result of the effect of tax rates in foreign jurisdictions.
(Stated in thousands of dollars except per share amounts and percentages)
| |
Three-month periods ended December 31, |
|
|
Years ended December 31, |
|
| |
2016 |
|
2015 |
|
% Change |
|
|
2016 |
|
2015 |
|
% Change |
|
| Net loss |
(15,074 |
) |
(3,782 |
) |
n.m. |
|
|
(46,517 |
) |
(42,489 |
) |
9 |
|
| Loss per share - diluted |
(0.30 |
) |
(0.09 |
) |
n.m. |
|
|
(1.01 |
) |
(1.10 |
) |
(8 |
) |
| Adjusted EBITDA |
3,182 |
|
9,662 |
|
(67 |
) |
|
5,048 |
|
23,631 |
|
(79 |
) |
| Adjusted EBITDA per share - diluted |
0.06 |
|
0.23 |
|
(74 |
) |
|
0.11 |
|
0.61 |
|
(82 |
) |
| Adjusted EBITDA as a percentage of revenue |
7 |
% |
17 |
% |
|
|
|
3 |
% |
8 |
% |
|
|
As a result of weak drilling activity and lower average day rates across all of the Corporation's operating segments, the
Corporation generated net losses for the three-month period and year ended December 31, 2016. Adjusted EBITDA as a percentage of
revenue for the three-month period and year ended December 31, 2016 was 7 percent and 3 percent, respectively (2015 - 17 percent
and 8 percent).
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 December 31, |
|
Years ended December 31, |
|
| |
2016 |
|
2015 |
|
% Change |
|
2016 |
|
2015 |
|
% Change |
|
| Revenue |
19,581 |
|
16,244 |
|
21 |
|
53,996 |
|
85,563 |
|
(37 |
) |
| Reportable segment loss before tax |
(18,479 |
) |
(1,337 |
) |
n.m. |
|
(33,121 |
) |
(30,698 |
) |
- |
|
For the three-month period ended December 31, 2016, PHX Energy's Canadian revenue increased by 21 percent to $19.6 million
from $16.2 million in the 2015-quarter. The increased revenue was primarily attributed to higher activity levels
quarter-over-quarter. The 2,632 operating days generated in the 2016-quarter were 37 percent greater than the 1,923 days in the
comparable 2015-period. In comparison, the number of total drilling days in the industry increased by 3 percent
quarter-over-quarter and the number of horizontal and directional wells increased by approximately 17 percent from 1,238 in the
2015-quarter to 1,450 in the 2016-quarter. (Source: Peter & Co. Limited & Daily Oil Bulletin)
The increase in the Corporation's activity in the quarter was however offset by lower average day rates, as weak commodity
prices persisted and the Corporation continued to experience significant pricing pressures from its customers. Excluding Stream
revenue of $1.0 million, in the final quarter of 2016 day rates dropped 15 percent from $8,296 in the 2015-quarter to $7,064.
PHX Energy grew its quarterly market share in Canada to approximately 25 percent, one of the highest levels in the
Corporation's history. This is a testament to the level of performance its operations team provides at the well site, and the
strong relationships its marketing team has formed. In the fourth quarter of 2016, PHX Energy's Canadian division was active
in the Montney, Wilrich, Bakken, Shaunavon, and Viking areas.
For the year ended December 31, 2016, PHX Energy's Canadian revenue decreased by 37 percent to $54.0 million from $85.6
million in 2015. The decrease in revenue was mainly due to the decline in the number of operating days and average day rates. The
number of operating days in the 2016-year totaled 6,997, a 20 percent reduction from the 8,766 days reported in 2015. In
comparison, Canadian industry activity, as measured by wells drilled, decreased by 24 percent to 3,845 horizontal and directional
wells in the 2016-year as compared to 5,047 horizontal and directional wells in 2015. (Source: Daily Oil Bulletin) Average day
rates for the 2016-year, excluding Stream revenue of $2.0 million, were $7,425, a decrease of 22 percent from the day rate of
$9,530 in 2015.
Reportable segment loss before tax for the three-month period and year ended December 31, 2016 was $18.5 million (2015 - $1.3
million) and $33.1 million (2015 - $30.7 million), respectively. Included in the Canadian segment's 2016 fourth quarter
reportable segment loss was an adjustment to the intercompany lease of drilling and other equipment between the Canadian and US
segments of $11.8 million. Included in the Canadian segment's loss in the 2015-year was an impairment loss of $13.8 million on
goodwill and intangible assets related to the Stream division.
The Canadian segment's profitability in both 2016-periods was impacted by lower average day rates, and profitability for the
2016-year was additionally impacted by decreased activity levels in the first three quarters. In addition, the segment's margins
were negatively affected by provisions for inventory, a provision for an onerous lease contract, and higher depreciation and
amortization from the change in the estimate of residual values of the Corporation's drilling equipment.
Stream Services
Contained within the Canadian segment for the three-month period and year ended December 31, 2016 were Stream revenues of $1.0
million (2015 - $0.3 million) and $2.0 million (2015 - $2.0 million), respectively. The Stream division incurred losses of $1.6
million in the final quarter of 2016 (2015 - $1.8 million) and $6.6 million for the 2016-year (2015 - $21.9 million). Included in
the losses for the 2016-quarter and year were provisions for obsolete electronic drilling recorder ("EDR") inventory of $0.3
million (2015 - nil). Additionally, the 2015-year losses included a $13.8 million impairment loss of on goodwill and intangible
assets related to older versions of the Corporation's EDR technology. It is anticipated that Stream's losses will decrease
as activity and revenue increase and positive margins will be achieved in future quarters of 2017. The Corporation will continue
to leverage existing resources to support the expansion of this service offering to achieve greater margins.
United States
(Stated in thousands of dollars)
| |
Three-month periods ended December 31, |
|
|
Years ended December 31, |
|
| |
2016 |
2015 |
|
% Change |
|
|
2016 |
|
2015 |
|
% Change |
|
| Revenue |
21,721 |
34,587 |
|
(37 |
) |
|
78,593 |
|
177,085 |
|
(56 |
) |
| Reportable segment profit (loss) before tax |
6,039 |
(3,598 |
) |
n.m. |
|
|
(16,556 |
) |
(11,352 |
) |
46 |
|
For the three-month period ended December 31, 2016, the US segment realized revenue of $21.7 million, a decrease of 37 percent
from the $34.6 million generated in the 2015-period. The decrease in revenue for the fourth quarter of 2016 was primarily caused
by lower activity and average day rates. PHX Energy's US operating days decreased to 1,734 days in the final quarter of 2016, a
reduction of 19 percent over the 2,147 days in the same 2015-period. In comparison, industry activity has declined 18 percent
with the number of horizontal and directional rigs running per day falling to 530 in the fourth quarter of 2016 from 650 rigs in
the comparative 2015-quarter. (Source: Baker Hughes) As a result of continued pricing pressures, average day rates, excluding the
motor rental division, decreased by 22 percent in the 2016-quarter to $12,175 from $15,627 in the 2015-quarter.
The US industry was predominantly focused on oil well drilling in the 2016-year, and this was led by the Permian basin which
represented 39 percent of the average rig count in the 2016 fourth quarter. Oil well drilling, as measured by wells drilled and
excluding the motor rental division, in the three-month period ended December 31, 2016 represented 91 percent of PHX Energy's US
activity. Phoenix USA remained active in the Permian, Eagle Ford, Mississippian/Woodford, Marcellus, Niobrara, Bakken and Utica
basins during the 2016-quarter.
Reportable segment profit before tax for the three-month period ended December 31, 2016 was $6.0 million as compared to a loss
of $3.6 million in the comparative 2015-period. The improved profitability of the US segment was primarily related to the
adjustment on leased drilling and other equipment from the Canadian operating segment in the amount of $11.8 million.
For the year ended December 31, 2016, US revenue decreased from $177.1 million in 2015 to $78.6 million, a reduction of 56
percent. The Corporation's US operating days decreased by 46 percent to 6,055 days compared to 11,189 days in 2015. In
comparison, US industry activity, as measured by the average number of horizontal and directional rigs running on a daily basis,
also fell by 46 percent to 449 rigs in 2016 compared to 839 rigs in 2015. (Source: Baker Hughes) Phoenix USA's average day rates,
excluding the motor rental division, declined by 17 percent in the 2016-year to $12,613 from $15,188 in 2015.
For the year ended December 31, 2016, reportable segment loss before tax increased by 46 percent to $16.6 million compared to
the $11.4 million in 2015. The significant decline in profitability realized in the 2016-year was primarily the result of
reductions in drilling activity and average day rates over the comparable 2015-period, partially offset by the intercompany lease
adjustment of $11.8 million in the fourth quarter of 2016.
International
(Stated in thousands of dollars)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
|
| |
2016 |
2015 |
% Change |
|
2016 |
|
2015 |
% Change |
|
| Revenue |
5,327 |
5,307 |
- |
|
15,812 |
|
24,132 |
(34 |
) |
| Reportable segment profit (loss) before tax |
1,011 |
327 |
n.m. |
|
(455 |
) |
3,881 |
n.m. |
|
In the fourth quarter of 2016, the Corporation generated the same level of international revenue as in the 2015-quarter, $5.3
million. With Phoenix Albania recommencing operations, international operating days in the 2016-quarter increased slightly to 709
days from 694 days in the 2015-quarter. The Corporation generated 11 percent of its 2016 fourth quarter consolidated revenue from
its international operations, which is up from the 8 percent reported in the 2015-quarter.
For the year ended December 31, 2016, revenue decreased by 34 percent to $15.8 million from $24.1 million in the comparable
2015-period. International operating days were down 12 percent year-over-year totaling 2,485 days in 2016, as compared to the
2,829 days in the 2015-period. The decreased revenue and operating days for the 2016-year were the result of idle operations in
Albania for the majority of 2016.
During the fourth quarter of 2016, Russian revenue increased to $4.5 million, which is 20 percent greater than the $3.7
million recorded in the comparable 2015-quarter. The increased revenue was mainly a result of increased activity and the stronger
ruble. Russian operating days increased by 6 percent in the 2016-quarter to 586 days from 555 days in 2015-quarter.
Reportable segment profit from international operations for the three-month period ended December 31, 2016 was $1.0 million
(19 percent of revenue), compared to $0.3 million (6 percent of revenue) generated in the corresponding 2015-period. The
higher margins realized in the 2016-quarter was mainly driven by Albania resuming activity and the marginal strengthening of the
Russian ruble against the Canadian dollar in the last quarter of 2016. For the year ended December 31, 2016, reportable
segment loss was $0.5 million as compared to a profit of $3.9 million (16 percent of revenue) in the 2015-period. The decrease in
the international operations' profitability in 2016 was a result of the idle operations in Albania for the most part of 2016.
Investing Activities
Net cash used in investing activities for the year ended December 31, 2016 was $5.1 million, a decrease of $21.9 million from
the $27.0 million used in 2015. During the 2016-year, PHX Energy spent a total of $7.8 million on the acquisition of drilling and
other equipment (2015 - $18.0 million) and received net proceeds of $4.5 million from the involuntary disposal of drilling
equipment in well bores (2015 - $4.8 million). The 2016 capital expenditures included:
- $4.7 million in measurement while drilling ("MWD") systems and spare components;
- $1.4 million in EDR systems and spare components;
- $0.7 million in machinery and equipment;
- $0.5 million in downhole performance drilling motors; and
- $0.5 million in other assets, including leasehold improvements.
The capital expenditure program undertaken in the year was financed generally from a combination of funds from operations,
long-term debt, equity financing proceeds, and working capital.
During the year, the Corporation spent $3.8 million in intangible assets as follows:
- $3.1 million related to a license agreement;
- $0.3 million in technology development;
- $0.1 million in systems and software; and
- $0.3 million in development costs.
The change in non-cash working capital balances of $1.9 million (source of cash) for the year ended December 31, 2016, relates
to the net change in the Corporation's trade payables that are associated with the acquisition of capital assets. This compares
to a $5.6 million (use of cash) for the year ended December 31, 2015.
Financing Activities
The Corporation reported cash used in financing activities of $2.0 million in 2016 as compared to $28.3 million in 2015. In
the 2016-year:
- the Corporation made aggregate repayments of $25.0 million on its operating facility and syndicated facility;
- through a bought deal financing and a concurrent private placement, the Corporation issued 9,120,407 common shares for net
proceeds of $23.2 million;
- the Corporation paid dividends of $0.4 million to shareholders; and
- issued 116,399 common shares for proceeds of $0.2 million upon the exercise of share options.
Capital Resources
As of December 31, 2016, the Corporation had $27.0 million drawn on its syndicated facility, $6.0 million drawn on its
Canadian operating facility and USD$1.5 million on its US operating facility.
On March 14, 2016, the Corporation reduced the maximum principal amount available under the Syndicated Credit Facility from
CAD$90 million to CAD$70 million. The purpose of the decrease was to reduce the standby fees charged on unused balances
under the credit facilities.
On November 7, 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 CAD$70.0
million to CAD$48.0 million, the Operating Facility from CAD$15.0 million to CAD$10.0 million and the US Operating Facility
from USD$2.5 million to USD$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 CAD$10.0 million.
- For the periods ending December 31, 2016 and thereafter, the following covenant EBITDA formulae and financial covenants
came into effect:
| |
|
Debt to |
|
Interest |
| |
|
Covenant |
|
Coverage |
| Quarter Ending |
Covenant EBITDA Formula |
EBITDA Ratio |
|
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 requires the Corporation's net capital expenditures and intangible costs to not
exceed budget for each fiscal year that is $31.8 million in 2017 and $17.5 million in 2018. The covenant also provides an
incremental $8.0 million that can be used in any of the fiscal years for the remaining tenor of the credit facilities.
- 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.
As at December 31, 2016, the Corporation was in compliance with all its financial covenants as follows:
| Ratio |
Covenant |
|
As at December 31, 2016 |
| Debt to covenant EBITDA |
Waived |
|
Waived |
| Interest coverage ratio |
Waived |
|
Waived |
| Net capital expenditures and intangible asset acquisitions |
< $10.5 million |
|
$7.0 million |
| Minimum liquidity |
> $10.0 million |
|
$30.0 million |
As at December 31, 2016, PHX Energy exceeded the minimum liquidity required under the amended credit agreement as the
Corporation had $7.0 million in cash-on-hand and $23.0 million available to be drawn from its credit facilities.
The credit facilities are secured by substantially all of the Corporation's assets.
Cash Requirements for Capital Expenditures
Historically, the Corporation has financed its capital expenditures and acquisitions through cash flows from operating
activities, debt and equity. The 2017 capital budget has been set at $25.0 million subject to quarterly review of the Board of
Directors. These planned expenditures are expected to be financed mainly from the proceeds of the equity financing completed on
February 2, 2017. However, if a sustained period of market and commodity price uncertainty and financial market volatility
persists in 2017, the Corporation's activity levels, cash flows and access to credit may be negatively impacted, the proceeds
from the equity financing may be required to fund operations, 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
Although 2016 will be remembered as one of the most challenging years in the Corporation's history, in the fourth quarter of
2016 there were some signs of recovery. In the first months of 2017, industry activity has continued to show signs of improvement
as commodity prices have appeared to stabilize.
In North America, PHX Energy's 2017 operating days are currently ahead of forecast, continuing the momentum that started to
take hold in the fourth quarter of 2016. Canadian operations grew market share adding to PHX Energy's client base, and in
the US, marketing efforts continued to focus on the operating regions with higher volumes of activity, namely the Permian basin.
Activity also improved in the Corporation's international operations during the fourth quarter of 2016. PHX Energy continues
to view Russia as a very attractive market and expects to see further growth in coming quarters.
Although rig counts are moving in a positive direction, the industry is slow to accept much needed improvements to pricing for
directional drilling services. Day rates charged to clients dropped far below what would be considered sustainable levels
during the depths of the downturn in 2016 and PHX Energy is anticipating day rates will somewhat recover as market conditions
stabilize.
Even with the positive trends developing in the industry, Management remains diligently focused on the financial position of
the Corporation and continues to execute strategies to protect its financial health. In 2016, long-term debt was reduced by
$31.0 million and numerous cost saving initiatives were implemented. This disciplined approach to financial management will
continue as the industry recovers. PHX Energy has already completed an equity financing in 2017 with the intention of using the
net proceeds of $29.3 million to reduce bank indebtedness, which will then be available to be redrawn and applied to fund the
Corporation's capital expenditure program. The Corporation sees many opportunities in 2017 and the bulk of this capital
spending is earmarked for higher margin products that will fuel growth in 2017, mainly Stream's EDR technology and Velocity
Real-Time System ("Velocity").
Technology Development
One of PHX Energy's core strategies is focused on providing differentiating technology that enables a higher level of drilling
performance, optimizes drilling efficiencies and supports growth in sectors with greater profitability. The Corporation
remained committed to this strategy despite the challenges faced in 2016. Management adapted initiatives to ensure technology
development persisted in the downturn and PHX Energy would emerge with a strong competitive advantage.
One of the first differentiating technologies released as part of this strategy was an MWD platform that redefined the
capabilities and performance of traditional MWD systems. In 2015, PHX Energy introduced Velocity to the market. With superior
reliability and advanced downhole measurements, demand for this system quickly outpaced supply. In 2016, PHX Energy was able to
increase its fleet and the Corporation exited the year with a job capacity of 35 systems. The majority of Velocity systems were,
and continue to be, deployed in the Permian basin where the technology offers a significant advantage and the rig count is the
strongest in North America. Even with this expansion, the fleet is operating at maximum capacity and PHX Energy intends to
increase its fleet to 65 systems by the end of 2017. The Corporation will continue to leverage this technology to gain market
share, and in addition, is considering alternative business models that allow for accelerated market penetration with improved
margins.
In 2016, PHX Energy's EDR division, Stream, commercialized its DataStream EDR product line (the "DataStream EDR"). Since
its official release in the third quarter of 2016, the DataStream EDR has quickly gained acceptance in the Canadian
market. Stream was operating at maximum capacity by the end of 2016 and given the successful deployment of the new product
line, PHX Energy intends on increasing the DataStream fleet throughout 2017. The launch of the DataStream EDR platform is a
milestone for the Corporation as it has successfully diversified PHX Energy's service portfolio. Engineering and development
efforts are focused on expanding upon the core product offering to further differentiate Stream's services, with a focus on
greater automation of well site processes.
With the successful launch of Velocity and DataStream EDR, in 2017 the Corporation will focus its engineering efforts towards
the development of a new performance motor technology, with the vision of adding one of the most powerful performance drilling
motors on the market to its suite of differentiating products. Additionally, PHX Energy believes that the industry will continue
to demand greater well site intelligence as operators continue to be driven by efficiency. The Corporation has developed an
advanced well site system ("Connect") that offers customers enhanced access to data when used in combination with existing PHX
Energy commercial services. Connect has been operating as a standalone system in the Canadian market since the fourth
quarter of 2016.
As the next phase of its engineering initiatives reach commercialization, PHX Energy will continue to focus on creating a
competitive advantage by leveraging and integrating these technologies to offer a completely unique service model.
Michael Buker, President
February 22, 2017
Non-GAAP Measures
1) Adjusted EBITDA
Adjusted EBITDA, defined as earnings before finance expense, income taxes, depreciation and amortization, impairment losses on
goodwill and intangible assets, provisions for the settlement of litigations, equity and cash-settled share-based payments,
severance costs, provisions for inventory and provisions for onerous contracts, 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 certain 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 December 31, |
|
|
Years periods ended December 31, |
|
| |
2016 |
|
2015 |
|
|
2016 |
|
2015 |
|
| Net loss |
(15,074 |
) |
(3,782 |
) |
|
(46,517 |
) |
(42,489 |
) |
| Add: |
|
|
|
|
|
|
|
|
|
| |
Depreciation and amortization |
10,886 |
|
14,454 |
|
|
49,752 |
|
48,283 |
|
| |
Provision for (Recovery of) income taxes |
116 |
|
(3,229 |
) |
|
(13,383 |
) |
(13,577 |
) |
| |
Finance expense |
502 |
|
642 |
|
|
1,952 |
|
3,472 |
|
| |
Impairment losses on goodwill and intangible assets |
- |
|
- |
|
|
- |
|
13,824 |
|
| |
Provision for settlement of litigations |
- |
|
- |
|
|
- |
|
6,533 |
|
| |
Equity-settled share-based payments |
165 |
|
58 |
|
|
1,542 |
|
877 |
|
| |
Cash-settled share-based payments (recoveries) |
1,585 |
|
(70 |
) |
|
4,094 |
|
(305 |
) |
| |
Severance costs |
385 |
|
1,049 |
|
|
2,091 |
|
6,473 |
|
| |
Provision for inventory |
2,317 |
|
540 |
|
|
3,217 |
|
540 |
|
| |
Provision for onerous contracts |
2,300 |
|
- |
|
|
2,300 |
|
- |
|
| Adjusted EBITDA as reported |
3,182 |
|
9,662 |
|
|
5,048 |
|
23,631 |
|
| |
|
|
|
|
|
|
|
|
|
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 December 31, |
|
|
Years ended December 31, |
|
| |
2016 |
|
2015 |
|
|
2016 |
|
2015 |
|
| Net cash flows from operating activities |
359 |
|
18,353 |
|
|
5,091 |
|
61,303 |
|
| Add (deduct): |
|
|
|
|
|
|
|
|
|
| |
Changes in non-cash working capital |
1,791 |
|
(8,065 |
) |
|
(1,470 |
) |
(50,815 |
) |
| |
Interest paid |
400 |
|
781 |
|
|
1,382 |
|
3,120 |
|
| |
Income taxes paid (recovered) |
(490 |
) |
(1,540 |
) |
|
(4,444 |
) |
238 |
|
| Funds from operations |
2,060 |
|
9,529 |
|
|
559 |
|
13,846 |
|
| |
|
|
|
|
|
|
|
|
|
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 was 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; Casper, Wyoming; 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, Dublin, Ireland and Luxembourg City, Luxembourg.
PHX Energy markets its EDR technology and services in Canada through its division, Stream Services, which has an office and
operations center in Calgary, Alberta. EDR technology is marketed worldwide outside Canada through its wholly-owned subsidiary
Stream Services International Inc.
Consolidated Statements of Financial Position
| |
December 31, 2016 |
December 31, 2015 |
| ASSETS |
|
|
|
|
| Current assets: |
|
|
|
|
| |
Cash and cash equivalents |
$ |
7,007,293 |
$ |
9,007,808 |
| |
Trade and other receivables |
|
41,552,796 |
|
44,694,812 |
| |
Inventories |
|
24,988,472 |
|
30,261,260 |
| |
Prepaid expenses |
|
2,613,716 |
|
2,869,018 |
| |
Current tax assets |
|
5,293,489 |
|
4,996,279 |
| |
Total current assets |
|
81,455,766 |
|
91,829,177 |
| Non-current assets: |
|
|
|
|
| |
Drilling and other equipment |
|
121,172,229 |
|
166,113,852 |
| |
Goodwill |
|
8,876,351 |
|
8,876,351 |
| |
Intangible assets |
|
26,302,314 |
|
25,025,202 |
| |
Deferred tax assets |
|
10,687,684 |
|
1,581,847 |
| |
Total non-current assets |
|
167,038,578 |
|
201,597,252 |
| Total assets |
$ |
248,494,344 |
$ |
293,426,429 |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
| Current liabilities: |
|
|
|
|
| |
Operating facility |
$ |
6,031,547 |
$ |
- |
| |
Trade and other payables |
|
31,194,630 |
|
30,373,003 |
| |
Dividends payable |
|
- |
|
415,670 |
| |
Total current liabilities |
|
37,226,177 |
|
30,788,673 |
| Non-current liabilities: |
|
|
|
|
| |
Loans and borrowings |
|
29,014,050 |
|
60,000,000 |
| |
Provision for onerous contracts |
|
2,300,000 |
|
- |
| |
Deferred income |
|
1,566,671 |
|
1,700,003 |
| |
Total non-current liabilities |
|
32,880,721 |
|
61,700,003 |
| Equity: |
|
|
|
|
| |
Share capital |
|
237,539,242 |
|
213,604,045 |
| |
Contributed surplus |
|
6,817,458 |
|
5,390,124 |
| |
Retained earnings |
|
(82,910,425) |
|
(36,393,629) |
| |
Accumulated other comprehensive income |
|
16,941,171 |
|
18,337,213 |
| |
Total equity |
|
178,387,446 |
|
200,937,753 |
| |
|
|
|
|
| Total liabilities and equity |
$ |
248,494,344 |
$ |
293,426,429 |
Consolidated Statements of Comprehensive Income (Loss)
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
|
| |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
| |
|
(Unaudited) |
|
|
(Unaudited) |
|
|
|
|
|
|
|
| Revenue |
$ |
46,628,582 |
|
$ |
56,138,403 |
|
$ |
148,400,609 |
|
$ |
286,780,151 |
|
| Direct costs |
|
49,589,582 |
|
|
53,433,795 |
|
|
172,495,460 |
|
|
275,631,998 |
|
| Gross profit (loss) |
|
(2,961,000 |
) |
|
2,704,608 |
|
|
(24,094,851 |
) |
|
11,148,153 |
|
| Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
| Selling, general and administrative expenses |
|
9,914,244 |
|
|
7,663,549 |
|
|
31,627,880 |
|
|
37,282,867 |
|
| Research and development expenses |
|
669,028 |
|
|
498,380 |
|
|
2,000,895 |
|
|
2,287,739 |
|
| Finance expense |
|
501,767 |
|
|
641,842 |
|
|
1,952,106 |
|
|
3,471,589 |
|
| Other expense (income) |
|
912,033 |
|
|
911,126 |
|
|
224,052 |
|
|
3,814,985 |
|
| Impairment losses on goodwill and intangible assets |
|
- |
|
|
- |
|
|
- |
|
|
13,823,514 |
|
| Provision for settlement of litigations |
|
- |
|
|
- |
|
|
- |
|
|
6,533,426 |
|
| |
|
11,997,072 |
|
|
9,714,897 |
|
|
35,804,933 |
|
|
67,214,120 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Loss before income taxes |
|
(14,958,072 |
) |
|
(7,010,289 |
) |
|
(59,899,784 |
) |
|
(56,065,967 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Provision for (Recovery of) income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
| Current |
|
697,433 |
|
|
(1,819,060 |
) |
|
(4,606,066 |
) |
|
(3,381,800 |
) |
| Deferred |
|
(581,042 |
) |
|
(1,409,661 |
) |
|
(8,776,922 |
) |
|
(10,195,322 |
) |
| |
|
116,391 |
|
|
(3,228,721 |
) |
|
(13,382,988 |
) |
|
(13,577,122 |
) |
| Net loss |
|
(15,074,463 |
) |
|
(3,781,568 |
) |
|
(46,516,796 |
) |
|
(42,488,845 |
) |
| Other comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Foreign currency translation |
|
3,518,743 |
|
|
2,939,393 |
|
|
(1,396,042 |
) |
|
18,401,692 |
|
| Total comprehensive loss for the period |
$ |
(11,555,720 |
) |
$ |
(842,175 |
) |
$ |
(47,912,838 |
) |
$ |
(24,087,153 |
) |
| Loss per share - basic |
$ |
(0.30 |
) |
$ |
0.03 |
|
$ |
(1.01 |
) |
$ |
(1.10 |
) |
| Loss per share - diluted |
$ |
(0.30 |
) |
$ |
0.03 |
|
$ |
(1.01 |
) |
$ |
(1.10 |
) |
Consolidated Statements of Cash Flows
| |
Three-month periods ended December 31, |
|
Years ended December 31, |
|
| |
|
2016 |
|
|
2015 |
|
|
2016 |
|
|
2015 |
|
| Cash flows from operating activities: |
|
(Unaudited) |
|
|
(Unaudited) |
|
|
|
|
|
|
|
| Net loss |
$ |
(15,074,463 |
) |
$ |
(3,781,568 |
) |
$ |
(46,516,796 |
) |
$ |
(42,488,845 |
) |
| Adjustments for: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depreciation and amortization |
|
10,885,569 |
|
|
14,453,915 |
|
|
49,752,222 |
|
|
48,283,328 |
|
| |
Provision for (Recovery of) income taxes |
|
116,391 |
|
|
(3,228,721 |
) |
|
(13,382,988 |
) |
|
(13,577,122 |
) |
| |
Unrealized foreign exchange (gain) loss |
|
106,503 |
|
|
(497,923 |
) |
|
1,573,606 |
|
|
(2,038,079 |
) |
| |
Loss (Gain) on disposition of drilling equipment |
|
602,465 |
|
|
1,196,940 |
|
|
(114,656 |
) |
|
4,869,928 |
|
| |
Equity-settled share-based payments |
|
164,999 |
|
|
58,345 |
|
|
1,542,013 |
|
|
876,859 |
|
| |
Finance expense |
|
501,767 |
|
|
641,842 |
|
|
1,952,106 |
|
|
3,471,589 |
|
| |
Provision for bad debts |
|
172,881 |
|
|
179,251 |
|
|
369,159 |
|
|
217,658 |
|
| |
Provisions for inventory |
|
2,317,472 |
|
|
540,466 |
|
|
3,217,371 |
|
|
540,466 |
|
| |
Provision for onerous contracts |
|
2,300,000 |
|
|
- |
|
|
2,300,000 |
|
|
- |
|
| |
Impairment loss on goodwill and intangible assets |
|
- |
|
|
- |
|
|
- |
|
|
13,823,514 |
|
| |
Amortization of deferred income |
|
(33,333 |
) |
|
(33,333 |
) |
|
(133,332 |
) |
|
(133,332 |
) |
| |
Interest paid |
|
(400,684 |
) |
|
(780,363 |
) |
|
(1,382,272 |
) |
|
(3,119,874 |
) |
| |
Income taxes recovered (paid) |
|
490,316 |
|
|
1,540,046 |
|
|
4,444,822 |
|
|
(237,643 |
) |
| |
Change in non-cash working capital |
|
(1,790,922 |
) |
|
8,064,609 |
|
|
1,470,083 |
|
|
50,814,700 |
|
| Net cash from operating activities |
|
358,961 |
|
|
18,353,506 |
|
|
5,091,338 |
|
|
61,303,147 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Proceeds on disposition of drilling equipment |
|
1,321,100 |
|
|
1,436,669 |
|
|
4,535,991 |
|
|
4,759,662 |
|
| |
Acquisition of drilling and other equipment |
|
(2,555,072 |
) |
|
(873,270 |
) |
|
(7,811,179 |
) |
|
(18,028,835 |
) |
| |
Acquisition of intangible assets |
|
(1,569,283 |
) |
|
(269,343 |
) |
|
(3,757,344 |
) |
|
(8,131,382 |
) |
| |
Change in non-cash working capital |
|
489,600 |
|
|
(2,136,796 |
) |
|
1,890,757 |
|
|
(5,595,856 |
) |
| Net cash used in investing activities |
|
(2,313,655 |
) |
|
(1,842,740 |
) |
|
(5,141,775 |
) |
|
(26,996,411 |
) |
| Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Proceeds from issuance of share capital (net) |
|
194,748 |
|
|
68,369 |
|
|
23,438,637 |
|
|
34,379,712 |
|
| |
Dividends paid to shareholders |
|
- |
|
|
(137,166 |
) |
|
(415,670 |
) |
|
(12,817,698 |
) |
| |
Proceeds from (Repayment of) loans and borrowings |
|
9,014,048 |
|
|
(10,000,000 |
) |
|
(31,004,592 |
) |
|
(44,280,800 |
) |
| |
Payments under finance leases |
|
- |
|
|
(2,553 |
) |
|
- |
|
|
(95,411 |
) |
| |
Proceeds from (Repayment of) operating facility |
|
(2,837,814 |
) |
|
(302,930 |
) |
|
6,031,547 |
|
|
(5,503,176 |
) |
| Net cash from (used in) financing activities |
|
6,370,982 |
|
|
(10,374,280 |
) |
|
(1,950,078 |
) |
|
(28,317,373 |
) |
| Net increase (decrease) in cash and cash equivalents |
|
4,416,288 |
|
|
6,136,486 |
|
|
(2,000,515 |
) |
|
5,989,363 |
|
| Cash and cash equivalents, beginning of period |
|
2,591,005 |
|
|
2,871,322 |
|
|
9,007,808 |
|
|
3,018,445 |
|
| Cash and cash equivalents, end of period |
$ |
7,007,293 |
|
$ |
9,007,808 |
|
$ |
7,007,293 |
|
$ |
9,007,808 |
|