2018 Q33 Report CWC-2018Q1d.indd :39 PM

Transcription

1 2018 Q3 3 Report CWC-2018Q1d.indd :39 PM

2 CWC-2018Q1d.indd :39 PM

3 MANAGEMENT S DISCUSSION AND ANALYSIS ( MD&A ) Management s Discussion and Analysis ( MD&A ) is a review of the results of operations and liquidity and capital resources of CWC Energy Services Corp. (unless the context indicates otherwise, a reference in this MD&A to CWC, the Company, we, us, or our means CWC Energy Services Corp.). The following discussion and analysis provided by CWC is dated October 31, 2018 and should be read in conjunction with unaudited condensed interim consolidated financial statements for the three and nine months ended September 30, 2018, the audited annual financial statements for the year ended December 31, 2017 ("Annual Financial Statements"), and the annual management's discussion and analysis for the year ended December 31, 2017 ("Annual MD&A"). Additional information regarding CWC can be found in the Company s latest Annual Information Form ( AIF ). The condensed interim consolidated financial statements are prepared in accordance with IAS 34, Interim Financial Reporting, as issued by the International Accounting Standards Board ( IASB ) applicable to the preparation of financial statements. All amounts are expressed in Canadian dollars unless otherwise noted. Additional information relating to CWC, including the AIF, is available on SEDAR at Financial and Operational Highlights Three months ended September 30, Nine months ended September 30, $ thousands, except shares, per share amounts, and margins % % FINANCIAL RESULTS Revenue Contract drilling 10,633 10,130 5% 25,142 24,308 3% Production services 27,480 17,043 61% 84,141 50,487 67% 38,113 27,173 40% 109,283 74,795 46% Adjusted EBITDA (1) 6,002 4,055 48% 13,511 9,433 43% Adjusted EBITDA margin (%) (1) 16% 15% 12% 13% Funds from operations 6,002 4,055 48% 13,511 9,433 43% Net income (loss) and comprehensive income (loss) 326 (638) n/m (2) (1,545) (3,683) 58% Net income (loss) and comprehensive income (loss) margin (%) 1% (2%) n/m (2) (1)% (5%) n/m (2) Per share information: Weighted average number of shares outstanding basic and diluted 520,463, ,935, ,271, ,604,720 Adjusted EBITDA (1) per share - basic and diluted $0.01 $0.01 $0.03 $0.02 Net income (loss) per share basic and diluted $0.00 $0.00 $(0.00) ($0.01) $ thousands, except ratios September 30, 2018 December 31, 2017 FINANCIAL POSITION AND LIQUIDITY Working capital (excluding debt) (1) 19,469 19,543 Working capital (excluding debt) ratio (1) 2.8:1 2.6:1 Total assets 257, ,354 Total long-term debt (including current portion) 46,394 49,810 Shareholders' equity 185, ,519 (1) Please refer to the Reconciliation of Non-IFRS Measures section for further information. (2) Not meaningful. Page 1

4 Working capital (excluding debt) is similar to December 31, 2017 due to similar operational days and hours between CWC s Contract Drilling and Production Services segments. Long-term debt (including current portion) has decreased 7% from December 31, 2017 as positive funds from operations were used to fund capital expenditures, purchase shares under the Normal Course Issuer Bid ( NCIB ) and to repay debt. Highlights for the Three Months Ended September 30, 2018 Average Q crude oil pricing, as measured by WTI, of US$73.25/bbl was 8% higher than Q average price of US$67.97/bbl (Q3 2017: US$48.18/bbl). However, the price differential between Canadian heavy crude oil, as represented by WCS, and WTI widened at times during the quarter from US$19/bbl to US$36/bbl and even higher to US$50/bbl in October 2018 compared to the historical normalized range of US$10/bbl to US$15/bbl causing exploration and production ( E&P ) companies to delay and/or shorten their drilling programs. However, such heavy oil differentials has yet to have a similar slowdown effect to activity levels in our service rig division given the Company s focus on production services. Natural gas prices, as measured by AECO, increased 90% from an average of $1.14/GJ in Q to $2.17/GJ in Q (Q3 2017: $1.36/GJ), but continues to remain very low in historically terms. CWC s drilling rig utilization of 60% in Q (Q3 2017: 63%) exceeded Canadian Association of Oilwell Drilling Contractors ( CAODC ) industry average of 30%. Activity levels decreased 3% in Q compared to Q due to significant wet weather conditions in key operating areas (57 days of lost activity compared to 31 days in Q out of a possible 828 total days). In addition, significant customer driven improvements and upgrades to Rig #4 were completed during Q which delayed the rig from being in active service. On a positive note, average revenue per operating day of $21,263 increased 9% over the comparable year ago quarter of $19,424. CWC achieved service rig utilization of 45% in Q (Q3 2017: 47%) with 42,316 operating hours (a new Q3 Company record) being 49% higher than the 28,320 operating hours in Q as a result of the additional service rigs acquired from C&J Energy Production Services-Canada Ltd ( C&J Canada ). CWC s service rig utilization was also impacted by wet weather conditions during Q which resulted in 4,024 hours of lost activity (Q3 2017: 2,616 hours) out of a total 93,950 hours. The average revenue per hour of $628 increased 12% over the comparable year ago quarter of $559. Furthermore, Q average revenue per hour excluding its top volume customers of $664 was $36 per hour higher than Q average revenue per hour of $628 demonstrating CWC s ability to to pass on higher labour and fuel costs to the majority of its E&P customers. Revenue of $38.1 million, an increase of $10.9 million (40%) compared to $27.2 million in Q The increase is primarily a result of the addition of the service rig assets of C&J Canada. Adjusted EBITDA (1) of $6.0 million in Q3 2018, an increase of $2.0 million (46%) compared to $4.1 million in Q The increase in Adjusted EBITDA in Q is due to higher gross margin from Production Services, on higher operating hours partially offset by lower Contract Drilling rig activity and gross margins when compared to Q and higher selling and administrative costs due to the C&J Canada acquisition. CWC has achieved 21 continuous quarters of positive Adjusted EBITDA since Q Net income of $0.3 million, an increase of $0.9 million compared to a net loss of $0.6 million in Q The change in net income is primarily due to the higher Adjusted EBITDA, offset by higher finance, stock based compensation, depreciation and income tax expense. On July 27, 2018 the Company entered into an interest rate swap to effectively fix the interest rate at 4.00%, until June 28, 2023, on its Mortgage Loan. As of September 30, 2018 the mark-to-market value of the interest rate swap was nominal. During Q3 2018, 1,175,500 (Q3 2017: 1,402,000) common shares were purchased under CWC s Normal Course Issuer Bid ( NCIB ) and 1,309,000 common shares were cancelled and returned to treasury. Page 2

5 Highlights for the Nine Months Ended 30, 2018 CWC s drilling rig utilization in the first nine months of 2018 of 46% (2017: 49%) exceeded the CAODC industry average of 29%. Activity levels in 2018 have decreased 3% compared to 2017 due to significant wet weather conditions in key operating areas in Q which resulted in lost activity days. Year-to-date 2018 operating days of 1,131 (2017: 1,209 operating days) is the second most active since the acquisition of Ironhand Drilling Inc. in May For the first nine months of 2018, CWC's service rig utilization was 45% consistent with 45% in the same period in Activity levels in 2018 continue to set new Company records by increasing 54% to 125,125 operating hours (2017: 81,363 operating hours). The increase resulted from the additional service rigs acquired from C&J Canada. Revenue of $109.3 million, an increase of $34.5 million (46%) compared to $74.8 million in the first nine months of The increase is primarily a result of the addition of the service rig assets of C&J Canada. Adjusted EBITDA (1) of $13.5 million, an increase of $4.1 million (43%) compared to $9.4 million in the first nine months of The increase in Adjusted EBITDA is consistent with increased activity ($6.6 million) from Production Services due to the C&J Canada acquisition, offset by a decrease in Adjusted EBITDA in Contract Drilling ($0.9 million) and corporate expense of ($1.7 million). Net loss of $1.5 million, a decrease of $2.1 million (-58%) compared to a net loss of $3.6 million in the first nine months of The decrease in net loss is due primarily to an increase in Adjusted EBITDA from Production Services as a result of increased activity from the C&J Canada acquisition. At the request of the Company, the Bank Loan was reduced from $100 million to $75 million to reduce borrowing costs and standby charges. On June 29, 2018 the Company obtained a new five year credit facility (the Mortgage Loan ) in the principal amount of $12.8 million. The Mortgage Loan is secured by, among other things, a collateral mortgage from the Company in favour of the bank over properties located in Sylvan Lake, Brooks and Slave Lake Alberta. These new borrowing arrangements significantly reduce the Company s overall borrowing costs by reducing standby charges on the syndicated credit facilities (the Bank Loan ) and realizing a lower interest rate on the term Bank Loan. The Mortgage Loan has been amortized over 22 years with blended monthly principal and interest payments. On July 27, 2018 the Company entered into an interest rate swap to effectively fix the interest rate at 4.00% until June 28, As of September 30, 2018 the mark-to-market value of the interest rate swap was nominal. For the nine months ended September 30, 2018, the Company purchased 3,593,000 (2017: 3,088,500) common shares under its NCIB and 3,563,000 (2017: 3,088,500) common shares were cancelled and returned to treasury. (1) Please refer to the Reconciliation of Non-IFRS Measures section for further information Page 3

6 Corporate Overview CWC Energy Services Corp. is a premier contract drilling and well servicing company operating in the Western Canadian Sedimentary Basin ("WCSB") with a complementary suite of oilfield services including drilling rigs, service rigs, swabbing rigs and coil tubing units. The Company's corporate office is located in Calgary, Alberta, with operational locations in Nisku, Grande Prairie, Slave Lake, Sylvan Lake, Drayton Valley, Lloydminster, Provost and Brooks, Alberta. The Company s shares trade on the TSX Venture Exchange under the symbol CWC. Operational Overview Contract Drilling CWC Ironhand Drilling, the Company's Contract Drilling segment, has a fleet of nine telescopic double drilling rigs with depth ratings from 3,200 to 5,000 metres, eight of nine rigs have top drives and three have pad rig walking systems. All of the drilling rigs are well suited for the most active depths for horizontal drilling in the WCSB, including the Montney, Cardium, Duvernay and other deep basin horizons. Part of the Company s strategic initiatives is to continue to increase the capabilities of its existing fleet to meet the growing demands of E&P customers for deeper depths at a cost effective price while providing a sufficient internal rate of return for CWC s shareholders. Sep. 30, 2018 Jun. 30, 2018 Mar. 31, 2018 Three months ended Dec. 31, 2017 Sep. 30, 2017 Jun. 30, 2017 Mar 31, 2017 Dec. 31, 2016 OPERATING HIGHLIGHTS Drilling Rigs Active drilling rigs, end of period Inactive drilling rigs, end of period Total drilling rigs, end of period Revenue per operating day (1) $21,263 $21,227 $23,485 $23,572 $19,424 $19,575 $20,942 $20,623 Drilling rig operating days Drilling rig utilization % (2) 60% 16% 61% 56% 63% 19% 66% 31% CAODC industry average utilization % 30% 17% 52% 28% 29% 17% 40% 24% Wells drilled Average days per well Meters drilled (thousands) Meters drilled per day Average meters per well 3,786 3,724 3,593 4,270 3,869 2,684 3,702 3,906 (1) Revenue per operating day is calculated based on operating days (i.e. spud to rig release basis). New or inactive drilling rigs are added based on the first day of field service. (2) Drilling rig utilization is calculated based on operating days (i.e. spud to rig release basis) in accordance with the methodology prescribed by the CAODC. Contract Drilling revenue of $10.6 million for Q (Q3 2017: $10.1 million) was achieved with a utilization rate of 60% (Q3 2017: 63%), compared to the CAODC industry average of 30%. CWC had 500 drilling rig operating days in Q3 2018, a 4% decrease from the 522 drilling rig operating days in Q3 2017, The reduced operating days were due to significant wet weather conditions in key operating areas in Q (57 days of lost activity compared to 31 days in Q out of a possible 828 total days). However, Q average revenue per operating day of $21,263 increased 9% over the $19,424 in Q In addition, significant customer driven improvements and upgrades to Drilling Rig #4 were completed during Q which delayed the rig from being in active service. This upgrade is expected to increase the drilling rig s capacity resulting in higher expected utilization for future quarters. Page 4

7 Production Services With a fleet of 148 service rigs, CWC is the largest well servicing company in Canada as measured by operating hours. CWC s service rig fleet consists of 77 single, 57 double, and 14 slant rigs providing services which include completions, maintenance, workovers and abandonments with depth ratings from 1,500 to 5,000 metres. CWC has chosen to park 46 of its service rigs and focus its sales and operational efforts on the remaining 102 active service rigs. Starting in October 2018, CWC has chosen to park another 10 of its active service rigs as a result of the tight labour market for field employees and the inability to crew these service rigs. The reduction of these 10 service rigs results in an active service rig fleet of 92 rigs for Q4 2018, which will still make CWC the largest well servicing company in Canada by operating hours. CWCs fleet of nine coil tubing units consist of four Class I and five Class II coil tubing units having depth ratings from 1,500 to 3,200 metres. The Company continues to focus its sales and operational efforts on servicing SAGD wells that are shallower in depth and more appropriate for coil tubing operations. CWC s fleet of 13 swabbing rigs were acquired as part of the C&J Canada acquisition and operate under the trade name CWC Swabtech. The swabbing rigs are used to remove liquids from the wellbore and allow reservoir pressures to push the commodity up the tubing casing. The Company has chosen to park four of its swabbing rigs and focus its sales and operational efforts on the remaining nine active swabbing rigs. Three months ended OPERATING HIGHLIGHTS Sep. 30, 2018 Jun. 30, 2018 Mar. 31, 2018 Dec. 31, 2017 Sep. 30, 2017 Jun. 30, 2017 Mar. 31, 2017 Dec. 31, 2016 Service Rigs Active service rigs, end of period Inactive service rigs, end of period Total service rigs, end of period Operating hours 42,316 28,831 53,979 40,879 28,320 20,047 32,997 27,091 Revenue per hour $628 $642 $637 $606 $559 $551 $584 $536 Revenue per hour excluding top volume customers $664 $677 $681 $645 $610 $608 $641 $590 Service rig utilization % (1) 45% 30% 56% 46% 47% 33% 56% 45% Coil Tubing Units Active coil tubing units, end of period Inactive coil tubing units, end of period Total coil tubing units, end of period Operating hours 898 1,212 3,007 1,978 1,783 1,557 4,243 2,349 Revenue per hour $731 $762 $724 $728 $688 $657 $491 $507 Coil tubing units utilization % (2) 12% 17% 39% 24% 22% 19% 52% 32% Swabbing Rigs Active Swabbing rigs, end of period Inactive swabbing rigs, end of period Total swabbing rigs, end of period Operating hours ,258 1,063 Revenue per hour $273 $265 $310 $286 Swabbing rig utilization % (1) 11% 13% 31% 19% (1) Service and swabbing rig utilization is calculated based on 10 hours a day, 365 days a year. New service and swabbing rigs are added based on the first day of field service. Service and swabbing rigs requiring their 24,000 hour recertification, refurbishment or have been otherwise removed from service for greater than 90 days are excluded from the utilization calculation until their first day back in field service. (2) Coil tubing unit utilization is calculated based on 10 hours a day, 365 days a year. New coil tubing units are added based on the first day of field service. Coil tubing units that have been removed from service for greater than 90 days are excluded from the utilization calculation until their first day back in field service. Production Services revenue was $27.5 million in Q3 2018, up $10.5 million (61%) compared to $17.0 million in Q as a result of adding an additional 36 active service rigs and 9 active swabbing rigs primarily from the C&J Canada acquisition. CWC achieved service rig utilization of 45% in Q (Q3 2017: 47%) with 42,316 operating hours (a new Q3 Company record) being 49% higher than the 28,320 operating hours in Q as a result of these additional service rigs from C&J Canada. The Company s service rig utilization was also impacted by wet weather conditions during Q which resulted in 4,024 hours Page 5

8 of lost activity (Q3 2017: 2,616 hours) out of a total 93,950 hours. The Q average revenue per hour of $628 increased 12% over the $559 in Q Furthermore, Q average revenue per hour excluding the top volume customers of $664 was $36 per hour higher than Q average revenue per hour of $628 demonstrating CWC s ability to to pass on higher labour and fuel costs to the majority of its E&P customers. CWC achieved coil tubing utilization of 12% in Q (Q3 2017: 22%) with 898 operating hours being 50% lower than the 1,783 operating hours in Q Q operating hours were negatively impacted by the continuation of very low natural gas prices and widening heavy oil differentials between WCS and WTI in SAGD operating areas causing delays in allocation and commitment of capital by our E&P customers. Average revenue per hour for coil tubing services of $731 in Q is 6% higher than $688 in Q3 2017, which reflects pricing improvements. CWC achieved swabbing rig utilization of 11% in Q (Q3 2017: nil) with 881 operating hours. The low activity level reflects the continuation of very low natural gas prices as CWC s swabbing rigs are used primarily to remove liquids from shallow natural gas wellbores. Outlook The steady rise in crude oil prices throughout 2017 has continued through the first nine months of Crude oil, as represented by WTI, averaged US$73.25/bbl in Q3 2018, an increase of 8% over Q average price of US$67.97/bbl and 52% higher than US$48.18/bbl in Q However, the price differential between Canadian heavy crude oil, as represented by WCS, and WTI widened further during the third quarter of 2018 to a range of US$19/bbl to US$36/bbl and even higher to US$50/bbl in October 2018 compared to the historical normalized range of US$10/bbl to US$15/bbl causing E&P companies to delay and/or shorten their drilling programs. However, such heavy oil differentials has yet to have a similar slowdown effect to activity levels in our service rig division given the Company s focus on production services. Natural gas prices, as represented by AECO, averaged $2.17/GJ, a 90% increase from Q average of $1.14/GJ, and 60% higher than $1.36/GJ in Q3 2017, yet remains very low in historical terms. With the backdrop of an improving crude oil price and a depressed natural gas price, the Petroleum Services Association of Canada ( PSAC ) on July 31, 2018 updated its 2018 forecast of number of wells drilled to 6,900 wells; a decrease of 500 wells or 6% compared to their January 31, 2018 forecast, and less than the 7,550 wells drilled in These Canadian heavy oil price differentials and low natural gas prices has resulted in the industry lowering its expectations for activity levels for the remainder of 2018 and into early Despite the Canadian heavy oil price differential and low natural gas prices, CWC has positioned its Contract Drilling and Production Services segments appropriately to minimize the impact of these commodity price differentials. The Company has positioned all nine of its drilling rigs in the WCSB on light oil and natural gas liquid plays, which have not experienced the same amount of pricing pressure as heavy oil. CWC currently has eight of its nine (89%) drilling rigs working and expects to have all nine (100%) drilling rigs working in Q and continuing through to Q spring breakup. In the Production Services segment, CWC has reduced the number of active service rigs from 102 rigs to 92 rigs in October 2018 as a result of a very tight labour market for field employees and the inability to crew these rigs. In addition, CWC has repositioned some of the service rigs working in heavy oil plays to new E&P customers in anticipation of a slowdown in heavy oil activity. Given the tight labour market for field employees and the resultant increase in wages needed to attract new field employees, CWC believes modest pricing increases with its E&P customers will continue in Q4 2018, but will be constrained by market pricing from our competitors limiting how far the Company will be able to increase day and hourly rates. CWC has sustainably positioned itself by providing its E&P customers with the highest quality service from the highest quality people at reasonable prices. However, uncertainties around the proposed Government of Canada s Bill C-69 legislation on the creation of the Canadian Energy Regulator and the Impact Assessment Act, which may impact the ability to develop new pipelines, will continue to negatively affect investment capital and growth in Canada s oil and gas industry in the near term. However, investment capital and growth are showing signs of returning as evident by the positive final investment decisions made on October 1, 2018 by proponents of a liquefied natural gas process facility (LNG Canada) in northeast British Columbia. CWC believes it would be very well positioned to benefit in the long-term once the liquefied natural gas processing facility comes online. While CWC remains focused on its operational and financial performance, it also recognizes the need to pursue opportunities that create long-term shareholder value. With the support of the Board of Directors, management continues to actively pursue opportunities to achieve higher utilization and EBITDA margins on its existing fleet while evaluating opportunities to consolidate the North American drilling and well servicing industry. CWC cautions that there are no guarantees that strategic opportunities will result in a transaction, or if a transaction is undertaken, as to its terms or timing. Page 6

9 Discussion of Financial Results Revenue, Direct Operating Expenses and Gross Margin Three months ended Nine months ended September 30, September 30, $ thousands $ % $ % Revenue Contract drilling 10,634 10, % 25,143 24, % Production services 27,479 17,043 10,436 61% 84,140 50,487 33,653 67% 38,113 27,173 10,940 40% 109,283 74,795 34,488 46% Direct operating expenses Contract drilling 8,311 7,233 1,078 15% 19,087 17,664 1,423 8% Production services 19,635 12,726 6,909 54% 63,109 38,077 25,032 66% 27,946 19,959 7,987 40% 82,196 55,741 26,455 47% Gross margin (1) Contract drilling 2,322 2,897 (575) (20)% 6,056 6,644 (588) (9)% Production services 7,845 4,317 3,528 82% 21,031 12,410 8,621 70% 10,167 7,214 2,953 41% 27,087 19,054 8,033 42% Gross margin percentage (1) Contract drilling 22% 29% n/a (7)% 24% 27% n/a (3%) Production services 29% 25% n/a 4% 25% 25% n/a -% 27% 27% n/a -% 25% 25% n/a -% (1) Please refer to the Reconciliation of Non-IFRS Measures section for further information. Q revenue of $38.1 million, an increase of $10.9 million (40%) compared to $27.2 million in Q Revenue increased $0.5 million (5%) in the Contract Drilling segment and increased $10.4 million (61%) in the Production Services segment in Q compared to Q For the nine months ended September 30, 2018, revenue of $109.3 million, an increase of $34.5 million (46%) compared to $74.8 million in the first nine months of Revenue increased $0.8 million (3%) in the Contract Drilling segment and $33.7 million (67%) in the Production Services segment for the first nine months of 2018 compared to the same period in CWC increased its revenue and diversified its customer base, reducing reliance on its top ten customers. Revenue contribution from the Company's top ten customers dropped to 56% for the first nine months of 2018 from 67% for the same period in 2017 with CWC s top customer s revenue contribution remaining the same at 20% in the first nine months of 2018 and Approximately 81% of revenue in the first nine months of 2018 was from work on crude oil wells, while 19% was from natural gas wells. Further, approximately 32% of revenue was related to drilling and completions work, 56% from maintenance and workovers on producing wells and 12% from abandonments. Many direct operating expenses, including labour costs related to field operating employees, are variable in nature and increase or decrease with activity levels such that changes in operating costs generally correspond to changes in revenue or activity levels. Contract Drilling s gross margin percentage of 22% in Q is lower than the 29% in Q due to reduced activity, lost days to wet weather conditions and increased scheduled repairs and maintenance. For the nine months ended September 30, 2018, Contract Drilling s gross margin of 24%, decreased 3% compared to 27% in the first nine months of Production Services gross margin of 29% in Q is higher than 25% in Q due to CWC ability to pass on higher labour and fuel costs to the majority of its E&P customers. For the nine months ended September 30, 2018, gross margin of 25% is consistent with that obtained in the first nine month of Page 7

10 Selling and Administrative Expenses Three months ended Nine months ended September 30, September 30, $ % $ % $ thousands Selling and administrative expenses 4,165 3,159 1,006 32% 13,576 9,621 3,955 41% Selling and administrative expenses of $4.2 million in Q3 2018, an increase of $1.0 million (32%) compared to $3.2 million in Q Selling and administrative expenses of $13.6 million for the six months ended September 30, 2018, an increase of $4.0 million (41%) compared to $9.6 million in For both the quarter and nine months ended September 30, 2018, the increased selling and administrative expenses are due to the 23 salaried employees that joined the Company primarily from the C&J Canada acquisition, additional costs to recruit field employees combined with other costs incurred due to significant higher year-over-year activity levels across all segments. Adjusted EBITDA (1) Three months ended Nine months ended September 30, September 30, $ % $ % $ thousands Adjusted EBITDA (1) Contract drilling 2,011 2,654 (643) (24%) 5,096 5,967 (871) (15%) Production services 5,389 2,373 3, % 12,929 6,308 6, % Corporate (1,398) (972) (426) 44% (4,514) (2,842) (1,672) 59% 6,002 4,055 1,947 48% 13,511 9,433 4,078 43% Adjusted EBITDA margin (%) (1) 16% 15% n/a 1% 12% 13% n/a (1%) (1) Please refer to the Reconciliation of Non-IFRS Measures section for further information. Management uses Adjusted EBITDA as a measure of the cash flow generated by the Company. Positive Adjusted EBITDA provides the cash flow needed to grow the business through purchase of equipment or business acquisitions, fund working capital, service and reduce outstanding long-term debt, pay a dividend or repurchase outstanding common shares under the Company's NCIB. Adjusted EBITDA of $6.0 million in Q3 2018, an increase of $1.9 million (48%) compared to $4.1 million in Q The increase in Adjusted EBITDA in Q is primarily due to the additional service rigs acquired from C&J Canada offset by reduced Contract Drilling activity due to wet weather conditions and increased Corporate expenses. For the nine months ended September 30, 2018, Adjusted EBITDA of $13.5 million, an increase of $4.1 million (43%) compared to $9.4 million for the same period in The increase in Adjusted EBITDA is primarily due to the additional service rigs acquired from C&J Canada offset by reduced Contract Drilling activity due to wet weather conditions in Q and an increase in Corporate expenses. Stock Based Compensation Three months ended Nine months ended September 30, September 30, $ thousands $ % $ % Stock based compensation % % Stock based compensation is primarily a function of outstanding stock options and restricted share units ( RSU's ) being expensed over their vesting term. Stock based compensation of $0.2 million in Q is consistent with $0.2 million in Q Page 8

11 Stock based compensation of $0.8 million for the nine months ended September 30, 2018, an increase of $0.2 million (29%) compared to $0.6 million in For both the quarter and nine months ended September 30, 2018, the increase in 2018 stock based compensation is primarily due to a greater number of stock options and RSU s granted to directors, management and employees for managing a larger pool of assets as a result of the C&J Canada acquisition. Finance Costs Three months ended Nine months ended September 30, September 30, $ thousands $ % $ % Finance costs % 1,899 1, % Finance costs of $0.6 million in Q3 2018, an increase of $0.3 million (85%) compared to $0.3 million in Q Finance costs of $1.9 million for the nine months ended September 30, 2018, an increase of 0.5 million (31%) compared to $1.4 million in For both the quarter and nine months ended September 30, 2018, the increase in finance costs was due to higher debt levels due to the acquisition and new Mortgage Loan on C&J Canada assets. Depreciation and Amortization Three months ended Nine months ended September 30, September 30, $ % $ % $ thousands Depreciation and amortization Contract drilling 1,818 1,830 (12) (1%) 4,194 4,242 (48) (1%) Production services 2,636 2,643 (7) -% 7,729 7,929 (200) (3%) Corporate % % 4,670 4, % 12,588 12, % Depreciation and amortization for drilling rigs, service rigs and swabbing rigs are based on operating days and hours. Coil tubing units, capitalized recertifications and other production equipment are depreciated on a straight line basis resulting in consistent depreciation and amortization expense regardless of activity. Amortization of Intangibles is based on estimated remaining life. As such, the change in depreciation for Q and the nine months ended September 30, 2018 predominately reflect changes in utilizations compared to the same periods in (Gain) Loss on Disposal of Equipment Three months ended Nine months ended September 30, September 30, $ thousands $ % $ % (Gain) Loss on disposal of equipment (57) (114) 57 n/m (1) 96 (72) 168 n/m (1) (1) Not meaningful. Management continually monitors the asset mix and equipment needs and invests and divests assets as needed to optimize operations. During Q and the first nine months of 2018, the (gain) loss on disposal of equipment was the result of the sale of equipment with proceeds on sale of $0.7 million (Q3 2017: $0.1 million) and $2.0 million (2017: $0.2 million) respectively. The equipment sold consisted primarily of one inactive coil tubing unit, one picker unit, one inactive service rig and various other vehicles. Page 9

12 Deferred Income Taxes Page 10 Three months ended Nine months ended September 30, September 30, $ thousands Net income (loss) before income taxes 532 (841) (1,835) (4,826) Deferred income tax expense (recovery) 206 (203) (290) (1,143) Deferred income tax expense (recovery) as a % of net income (loss) before income taxes 39% (24%) (16%) (24%) Expected statutory income tax rate 27% 27% 27% 27% Income taxes are a function of taxable income and are calculated differently than accounting net income. Differences between accounting net income and taxable income include such things as gains or losses on disposal of fixed assets, stock based compensation, differences between income tax estimates and actual tax filings, goodwill impairment, and other differences. The deferred income tax expense in Q and the deferred income tax recovery for the first nine months of 2018 of $0.2 million (Q3 2017: ($0.2) million) and ($0.3) million (2017: ($1.1) million) respectively, is a result of the net income (loss) before income taxes in each period. The Company has substantial tax pools and non-capital losses available to reduce future taxable income such that the Company does not expect to pay any cash taxes for the next several years. Net Income (Loss) and Comprehensive Income (Loss) Three months ended Nine months ended September 30, September 30, $ % $ % $ thousands Net Income (loss) and comprehensive income (loss) 326 (638) 964 n/m (1) (1,545) (3,683) 2,138 58% (1) Not meaningful. Net income (loss) and comprehensive income (loss) has increased $1.0 million year-over-year for the quarter and decreased $2.1 million for the nine months ended September 30, In Q3 2018, the increase in Adjusted EBITDA from the Contract Drilling and Production Services more than offset the higher corporate costs and Company depreciation, stock based compensation and finance costs. For the nine months ended September 30, 2018, the increase in Adjusted EBITDA from Production Services exceeded lower Adjusted EBITDA from Contract Drilling and increased Corporate expenses, depreciation and amortization. Liquidity and Capital Resources Source of Funds The Company s liquidity needs in the short-term and long-term can be sourced in several ways including: funds from operations, borrowing against existing credit facilities, new debt instruments, equity issuances and proceeds from the sale of assets. Cash inflows are used to repay outstanding amounts on the Company's credit facilities, acquire shares under the NCIB and fund capital requirements. During the first nine months of 2018, the Company s Funds from Operations of $13.5 million combined with a $0.1 million from common share issuances and $2.0 million proceeds on disposal of equipment was used to fund a $3.8 million reduction in long term debt, $9.2 million of capital expenditures, $1.8 million of interest on long-term debt and finance lease payments and $0.7 million in acquisitions of shares under the NCIB. At September 30, 2018 the Company had working capital (excluding debt) of $19.5 million compared to $19.5 million at December 31, (Please refer to the "Reconciliation of Non-IFRS Measures" section for further information). Typically, as activity levels increase or decrease working capital will also increase or decrease. During Q at the request of the Company the syndicated credit facility ( Bank Loan ) was reduced from $100 million to $75 million to reduce borrowing costs and standby charges. The $75 million Bank Loan provides financial security and flexibility

13 to July 31, 2020 and a quarterly financial covenant for Consolidated Debt to Consolidated EBITDA ratio of 4.00 to 1. The Bank Loan is secured by a general security agreement and a first charge security interest covering all of the assets of the Company. Under the terms of the Bank Loan, the Company is required to comply with certain financial covenants. The Company is in compliance with each of the financial covenants at September 30, The Company expects to be able to renew the Bank Loan prior to maturity. Effective September 30, 2018, the applicable rates under the Bank Loan are: bank prime rate plus 1.00%, banker s acceptances rate plus a stamping fee of 2.00%, and standby fee rate of 0.45%. On June 29, 2018 the Company obtained a new five year credit facility (the Mortgage Loan ) in the principal amount of $12.8 million. The Mortgage Loan is secured by, among other things, a collateral mortgage from the Company in favour of the bank over properties located in Sylvan Lake, Brooks and Slave Lake Alberta. These new borrowing arrangements significantly reduce the Company s overall borrowing costs by reducing standby charges on the syndicated Bank Loan and realizing a lower interest rate on the term Bank Loan. The Mortgage Loan has been amortized over 22 years with blended monthly principal and interest payments. On July 27, 2018 the Company entered into an interest rate swap to exchange the floating rate interest payments for fixed rate interest payments, which fix the Bankers Acceptance-Canadian Dollar Offered Rate components of its interest payment on the outstanding term debt. Under the interest rate swap agreement, the Company pays a fixed rate of 2.65% per annum plus the applicable credit spread of 1.35%, for an effective fixed rate of 4.0%. The fair value of the interest rate swap arrangement is the difference between the forward interest rates and the discounted contract rate. As of September 30, 2018 the mark-tomarket value of the interest rate swap was nominal. Capital Requirements On December 13, 2017 the Company announced its capital expenditure budget for 2018 of $12.7 million, $7.2 million of which is growth capital to improve certain drilling and coil tubing equipment while the remaining $5.5 million is maintenance and infrastructure capital related to recertification s, additions and upgrades to field equipment for the drilling rigs, service rigs, swabbing rigs and coil tubing divisions as well as information technology infrastructure. The increase to the 2018 capital expenditure budget compared to the 2017 capital expenditure of $6.8 million is consistent with CWC s commitment to safety and operational efficiency with high quality and well maintained equipment. CWC intends to finance its 2018 capital expenditure budget from operating cash flows. As utilization of the Company s equipment increases, CWC plans to recertify several of its service rigs. As at September 30, 2018, the Company has capital spending plans as noted in the section titled Capital Expenditures. Additional discretionary capital expenditures will be required in order to continue to grow the Company s assets and revenue in the future. It is anticipated future cash requirements for capital expenditures will be met through a combination of funds from operations and borrowing against existing credit facilities as required. However, additional funds may be raised by new debt instruments, equity issuances and proceeds from the sale of assets. CWC may require additional financing in the future to implement its strategies and business objectives. It is possible that such financing will not be available, or if available, will not be available on favorable terms. If CWC issues any shares in the future to finance its operations or implement its strategies, the current shareholders of CWC may incur a dilution of their interest. Common Shares and Dividends The following table summarizes outstanding share data and potentially dilutive securities: October 31, 2018 September 30, 2018 December 31, 2017 Common shares 519,154, ,154, ,378,958 Stock options 24,351,333 24,351,333 27,546,667 Restricted share units 4,579,332 4,579,332 5,135,332 During the nine months ended September 30, 2018, 1,033,335 stock options were exercised and 2,161,999 were forfeited. In addition, 305,667 RSU's were exercised, 54,000 were granted and 304,333 were forfeited. On April 10, 2018, the Company replaced its expired NCIB with a new NCIB which now expires on April 9, Under the new NCIB the Company may purchase, from time to time as it considers advisable, up to 26,057,889 of issued and outstanding common shares through the facilities of the TSXV or other recognized marketplaces. In addition, CWC entered into an automatic securities purchase plan (the ASPP ) (as defined under applicable securities laws) with Raymond James Ltd. ("Raymond James") for the purpose of making purchases under the ASPP. Such purchases will be determined by Raymond James in its sole discretion, without consultation with CWC having regard to the price limitation and aggregate purchase limitation and other terms of the ASPP and the rules of the TSXV. Conducting the NCIB as an ASPP allows common shares to be purchased at times when CWC would otherwise be prohibited from doing so pursuant to securities laws and its internal trading policies. Page 11

14 During the nine months ended September 30, 2018, 3,593,000 common shares were purchased under the NCIB and 3,563,000 common shares were cancelled and returned to treasury. Capital Expenditures Three months ended Nine months ended September 30, September 30, $ thousands $ % $ % Contract drilling 1,586 1, % 6,702 2,788 3, % Production services 1,110 1, % 3,040 2, % Corporate % % Total capital expenditures 2,696 2, % 9,770 5,626 4,144 74% Growth capital 1,581 1, % 5,859 1,735 4, % Maintenance and infrastructure capital 1,115 1,181 (66) (6)% 3,911 3, % Total capital expenditures 2,696 2, % 9,770 5,626 4,144 74% Capital expenditures for the first nine months of 2018 of $9.8 million are $4.1 million higher than $5.6 million in 2017 and primarily consist of drilling rig upgrades, recertification costs, replacement components and leased vehicles. Growth capital of $1.6 million in Q consists primarily of customer driven upgrades to Drilling Rig #4 (Q2 2018: $2.7 million) that included a pad rig walking system, increase drilling capacity, torque, pump pressure and dual fuel engine capabilities while operating on a smaller footprint. In Q2, 2018 Drilling Rig #2 upgrades of $1.0 million included a new mast, rising cylinders, catwalk and top drive integration. These upgrades are expected to increase these two drilling rigs capacity resulting in higher expected utilization for future quarters. Rig #2 and Rig #4 s upgrades align with our strategic initiatives and meet our E&P customers demands for deeper depths at cost effective prices while providing a sufficient internal rate of return for CWC s shareholders. The 2018 capital expenditure budget of $12.7 million was approved by the Board of Directors on December 13, 2017 comprised of $7.2 million of growth capital to improve certain drilling and coil tubing equipment while the remaining $5.5 million is maintenance and infrastructure capital related to recertification s, additions and upgrades to field equipment for the drilling rigs, service rigs, swabbing rigs and coil tubing divisions as well as information technology infrastructure. CWC anticipates total 2018 capital expenditures to be approximately $11.1 million, $1.6 million lower than originally budgeted. Commitments and Contractual Obligations Under the terms of the Company s amended Bank Loan, the borrowing under the Bank Loan are due in full on July 31, The Company is committed to monthly payments of interest and bank charges until July 31, The Company s Mortgage Loan is being amortized over 22 years with blended monthly principal and interest payments and matures on June 28, There have been no significant changes in other commitments or contractual obligations since December 31, Management believes that there will be sufficient cash flows generated from operations to service the interest on the debt and finance the required maintenance and growth capital of the Company in Page 12

15 Summary and Analysis of Quarterly Data $ thousands, except per share amounts Three months ended Sept. 30 June 30 March 31 Dec. 31 Sept. 30 June 30 March 31 Dec. 31 Revenue 38,113 22,245 48,925 37,420 27,173 15,114 32,580 20,922 Adjusted EBITDA 6, ,478 6,630 4, ,150 2,923 Net income (loss) 326 (3,067) 1,196 8,544 (638) (2,677) (368) (1,717) Net income (loss) per share: basic and diluted 0.01 (0.01) (0.01) Total assets 257, , , , , , , ,750 Total long-term debt 46,394 36,803 51,377 49,810 34,404 28,887 38,828 33,142 Shareholders' equity 185, , , , , , , ,482 The table above summarizes CWC s quarterly results for the previous eight financial quarters. CWC s operations are carried out in western Canada. The second quarter is typically expected to be the weakest financial and operating quarter for the Company due to ground conditions being impacted by spring breakup. The ability to move heavy equipment in the Canadian crude oil and natural gas fields is dependent on weather conditions. As warm weather returns in the spring, the winter s frost comes out of the ground rendering many secondary roads incapable of supporting the weight of heavy equipment until they have thoroughly dried out. The duration of this spring breakup has a direct impact on the Company s activity levels. In addition, many exploration and production areas in northern Canada are accessible only in winter months when the ground is frozen enough to support equipment. As a result, late March through May is traditionally the Company s slowest time, and as such the revenue, operating costs, and financial results of the Company will vary on a quarterly basis. Through the eight quarters presented, the amount of revenue and net income (loss), adjusted for the effects of seasonality, have fluctuated primarily due to changes in the utilization of equipment, changes in the day and hours billing rate, and the increase in the number of drilling rigs, service rigs, swabbing rigs and coil tubing units over the period as detailed in the section titled Operational Overview. Other significant impacts have been a result of: Q saw the completion of significant customer driven capital expenditure upgrades on Drilling Rig #4 to meet customer demands for deeper depths at cost effective prices. Wet weather conditions during the quarter significantly impacted activity levels in both the Contract Drilling and Production Services segments resulting in 7% and 4% of lost operating days and hours respectively. During Q3 2018, 1,175,500 common shares were purchased under the NCIB and a total of 1,309,000 common shares were cancelled and returned to treasury. Q saw significant customer driven capital expenditure upgrades to two drilling rigs to meet customer demands for deeper depths at cost effective prices. During Q2 2018, 1,023,000 common shares were purchased under the NCIB and a total of 935,500 common shares were cancelled and returned to treasury. Q service rig fleet set a new Company record of 53,979 operating hours as a result of the increase in the number of service rigs from the acquisition of the C&J Canada assets. During Q1 2018, 1,394,000 common shares were purchased under the NCIB and a total of 1,318,500 common shares were cancelled and returned to treasury. Q saw the acquisition of C&J Canada s service and swabbing rig assets for $37.5 million. Higher operating activity and pricing in the Contract Drilling and Production Services segments also contributed to the improved financial results compared to the previous quarters. CWC closed a rights offering for aggregate gross proceeds of $26.0 million ($25.9 million after deductions of shares issue costs) to partially finance the acquisition of the C&J Canada assets. Under the fully subscribed offering, 130,148,781 common shares were issued to shareholders who exercised their rights. During Q4 2017, 405,000 common shares were purchased under the NCIB and a total of 1,441,500 common shares were cancelled and returned to treasury. Q3 2017, 1,402,000 common shares were purchased under the NCIB and a total of 1,478,000 common shares were cancelled and returned to treasury. Q saw the initiation of a process to review strategic alternatives. During Q2 2017, 1,404,000 common shares were purchased under the NCIB and a total of 1,478,000 common shares were cancelled and returned to treasury. Q saw significantly higher operating activity in the Company s Contract Drilling and Production Services segments than what had been experienced in the last eight to twelve quarters. Page 13

16 Q saw improved utilizations in both drilling and service rig activity as a result of increased global crude oil and natural gas prices after OPEC s agreement on crude oil production cuts. Critical Accounting Estimates and Judgments This MD&A of the Company s financial condition and results of operations is based on the financial statements which are prepared in accordance with IFRS. The preparation of the financial statements in conformity with IFRS requires that certain estimates and judgments be made with respect to the reported amounts of revenue and expenses and the carrying amounts of assets and liabilities. These estimates are based on historical experience and management s judgment. Anticipating future events involves uncertainty and consequently the estimates used by management in the preparation of the financial statements may change as future events unfold, additional experience is acquired or the Company s operating environment changes. In many cases the use of judgment is required to make estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Further details of the nature of these estimates and assumptions may be found in the relevant notes to the Annual Financial Statements and the section titled Critical Accounting Estimates and Judgments in the Annual MD&A. There have been no significant or material changes in the nature of critical accounting estimates and judgements since December 31, The Company adopted IFRS 15 Revenue from Contracts with Customers and IFRS 9 Financial Instruments on January 1, The transitions had no material effect on the Company s Financial Statements. Please refer to the financial statements and related notes for further details on the adoption of these standards. CEO and CFO Certifications The CEO and CFO of TSX Venture Exchange listed companies, such as CWC, are not required to certify they have designed internal control over financial reporting, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Instead, an optional form of certification has been made available to TSX Venture Exchange listed companies and has been used by CWC s certifying officers for the September 30, 2018 interim filings. The certification reflects what the Company considers to be a more appropriate level of CEO and CFO certification given the size and nature of the Company s operations. This certification requires that the certifying officer s state: Page 14 They have reviewed the annual financial report and MD&A; That, based on their knowledge, they have determined there is no untrue statement of a material fact, or any omission of material fact required to be stated which would make any statement not misleading in light of the circumstances under which it was made within the annual filings; and That based upon their knowledge, the annual filings, together with the other financial information included in the annual filings, fairly present in all material respects the financial condition, financial performance and cash flows of the Company as of the date and for the periods presented in the annual filings. Risks and Uncertainties Certain activities of the Company are affected by factors that are beyond its control or influence. Additional risks and uncertainties that management may be unaware of, or that they determine to be immaterial, may also become important factors which affect the Company. Along with the risks discussed in this MD&A, other business risks faced by the Company may be found under Risk Factors in the Company s most recent Annual Information Form which is available under the Company s profile at or by contacting the Company. Forward-Looking Information This MD&A contains certain forward-looking information and statements within the meaning of applicable Canadian securities legislation. Certain statements contained in this MD&A, including most of those contained in the section titled Outlook and including statements which may contain such words as anticipate, could, continue, should, seek, may, intend, likely, plan, estimate, believe, expect, will, objective, ongoing, project and similar expressions are intended to identify forward-looking information or statements. In particular, this MD&A contains forward-looking statements including management s

17 assessment of future plans and operations, planned levels of capital expenditures, expectations as to activity levels, expectations on the sustainability of future cash flow and earnings and the ability to pay dividends, expectations with respect to crude oil and natural gas prices, activity levels in various areas, expectations regarding the level and type of drilling and production and related drilling and well services activity in the WCSB, expectations regarding entering into long term drilling contracts and expanding its customer base, and expectations regarding the business, operations, revenue and debt levels of the Company in addition to general economic conditions. Although the Company believes that the expectations and assumptions on which such forward-looking information and statements are based are reasonable, undue reliance should not be placed on the forward-looking information and statements because the Company can give no assurances that they will prove to be correct. Since forward-looking information and statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the drilling and oilfield services sector (ie. demand, pricing and terms for oilfield drilling and services; current and expected oil and gas prices; exploration and development costs and delays; reserves discovery and decline rates; pipeline and transportation capacity; weather, health, safety and environmental risks), integration of acquisitions, competition, and uncertainties resulting from potential delays or changes in plans with respect to acquisitions, development projects or capital expenditures and changes in legislation, including but not limited to tax laws, royalties and environmental regulations, stock market volatility and the inability to access sufficient capital from external and internal sources and the inability to pay dividends. Accordingly, readers should not place undue reliance on the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company s financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through SEDAR at The forward-looking information and statements contained in this MD&A are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking information or statements, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. Any forward-looking statements made previously may be inaccurate now. Page 15

18 Reconciliation of Non-IFRS Measures Three months ended Nine months ended September 30, September 30, $ thousands except share and per share amounts NON-IFRS MEASURES Adjusted EBITDA: Net income (loss) and comprehensive income (loss) 326 (638) (1,545) (3,683) Add: Depreciation 4,670 4,512 12,588 12,292 Finance costs ,899 1,448 Deferred income tax expense (recovery) 206 (203) (290) (1,143) Stock based compensation (Gain) Loss on sale of equipment (57) (114) 96 (72) Adjusted EBITDA (1) 6,002 4,055 13,511 9,433 Adjusted EBITDA per share basic and diluted (1) $0.01 $0.01 $0.03 $0.02 Adjusted EBITDA margin (Adjusted EBITDA/Revenue) (1) 16% 15% 12% 13% Weighted average number shares outstanding basic and diluted 520,463, ,704, ,271, ,301,324 Gross margin: Revenue 38,113 27, ,283 74,795 Less: Direct operating expenses 27,946 19,959 82,196 55,741 Gross margin (2) 10,167 7,214 27,087 19,054 Gross margin percentage (2) 27% 27% 25% 25% $ thousands September 30, 2018 December 31, 2017 Working capital (excluding debt): Current assets 30,022 31,745 Less: Current liabilities (11,438) (12,378) Add: Current portion of long term debt Working capital (excluding debt) (3) 19,469 19,543 Working capital (excluding debt) ratio (3) 2.8:1 2.6:1 Net debt: Long term debt 45,509 49,634 Less: Current assets (30,022) (31,745) Add: Current liabilities 11,438 12,378 Net debt (4) 26,925 30,267 (1) Adjusted EBITDA (Earnings before interest and finance costs, income tax expense, depreciation, amortization, gain or loss on disposal of asset, goodwill impairment, stock based compensation and other one-time gains and losses) is not a recognized measure under IFRS. Management believes that in addition to net income, Adjusted EBITDA is a useful supplemental measure as it provides an indication of the Company s ability to generate cash flow in order to fund working capital, service debt, pay current income taxes, pay dividends, repurchase common shares under the Normal Course Issuer Bid, and fund capital programs. Investors should be cautioned, however, that Adjusted EBITDA should not be construed as an alternative to net income (loss) determined in accordance with IFRS as an indicator of the Company s performance. CWC s method of calculating Adjusted EBITDA may differ from other entities and accordingly, Adjusted EBITDA may not be comparable to measures used by other entities. Adjusted EBITDA margin is calculated as Adjusted EBITDA divided by revenue and provides a measure of the percentage of Adjusted EBITDA per dollar of revenue. Adjusted EBITDA per share is calculated by dividing Adjusted EBITDA by the weighted average number of shares outstanding as used for calculation of earnings per share. (2) Gross margin is calculated from the statement of comprehensive loss as revenue less direct operating costs and is used to assist management and investors in assessing the Company s financial results from operations excluding fixed overhead costs. Gross margin percentage is calculated as gross margin divided by revenue. The Company believes the relationship between revenue and costs expressed by the gross margin percentage is a useful measure when compared over different financial periods as it demonstrates the trending relationship between revenue, costs and margins. Gross margin and gross margin percentage are non-ifrs measures and do not have any standardized meaning prescribed by IFRS and may not be comparable to similar measures provided by other companies. (3) Working capital (excluding debt) is calculated based on current assets less current liabilities excluding the current portion of long-term debt. Working capital (excluding debt) is used to assist management and investors in assessing the Company s liquidity. Working capital (excluding debt) does not have any meaning prescribed under IFRS and may not be comparable to similar measures provided by other companies. Working capital (excluding debt) ratio is calculated as current assets divided by the difference of current liabilities less the current portion of long term debt. (4) Net debt is not a recognized measure under IFRS and does not have any standardized meaning prescribed by IFRS and may not be comparable to similar measures provided by other companies. Management believes net debt is a useful indicator of a company s debt position. Page 16

19 CWC ENERGY SERVICES CORP. Unaudited Condensed Interim Consolidated Financial Statements For the three and nine months ended September 30, 2018 and 2017 Page 17

20 CWC ENERGY SERVICES CORP. CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (unaudited) September 30, December 31, Stated in thousands of Canadian dollars Note ASSETS Current Cash $ 154 $ 95 Accounts receivable 28,205 30,119 Prepaid expenses and deposits 1,663 1,531 30,022 31,745 Property and equipment 5 227, ,190 Intangibles $ 257,675 $ 264,354 LIABILITIES Current Accounts payable and accrued liabilities $ 10,553 $ 12,202 Current portion of long-term debt ,438 12,378 Deferred tax liability 15,533 15,823 Long-term debt 6 45,509 49,634 61,042 65,457 SHAREHOLDERS' EQUITY Share capital 7 265, ,720 Contributed surplus 10,393 8,609 Deficit (90,355) (88,810) 185, ,519 $ 257,675 $ 264,354 Page 18

21 CWC ENERGY SERVICES CORP. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the three and nine months ended September 30, 2018 and 2017 (unaudited) Three months ended September 30 Nine months ended September 30 Stated in thousands of Canadian dollars except per share amounts Note Revenue 10 $ 38,113 $ 27,173 $ 109,283 $ 74,795 Expenses 11 Direct operating expenses 27,946 19,959 82,196 55,741 Selling and administrative expenses 4,165 3,159 13,576 9,621 Stock based compensation Finance costs ,899 1,448 Depreciation and amortization 4,670 4,512 12,588 12,292 (Gain) loss on disposal of equipment (57) (114) 96 (72) 37,581 28, ,118 79,621 Net income (loss) before income taxes 532 (841) (1,835) (4,826) Deferred income tax expense (recovery) 206 (203) (290) (1,143) Net income (loss) and comprehensive income (loss) $ 326 $ (638) $ (1,545) $ (3,683) Net income (loss) per share Basic and diluted 7 $ - $ - $ - $ (0.01) See accompanying notes to the condensed interim consolidated financial statements. Page 19

22 CWC ENERGY SERVICES CORP. CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY For the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share amounts Note Number of Shares Share Capital Contributed Surplus Deficit Total Equity Balance - January 1, ,920,676 $ 242,306 $ 6,847 $ (93,671) $ 155,482 Net loss and comprehensive loss (3,683) (3,683) Stock based compensation expense Exercise of stock options 7 883, (62) Settlement of restricted share units 7 600, (138) - - Cancellation of common shares purchased under normal course issuer bid 7 (3,088,500) (1,908) 1,236 - (672) Balance September 30, ,316,342 $ 240,713 $ 8,474 $ (97,354) $ 151,833 Balance - January 1, ,378,958 $ 266,720 $ 8,609 $ (88,810) $ 186,519 Net loss and comprehensive loss (1,545) (1,545) Stock based compensation expense Exercise of stock options 7 1,033, (82) Settlement of restricted share units 7 305, (57) - - Cancellation of common shares purchased under normal course issuer bid 7 (3,563,000) (1,850) 1,160 - (690) Balance September 30, ,154,960 $ 265,157 $ 10,393 $ (90,355) $ 185,195 See accompanying notes to the condensed interim consolidated financial statements. Page 20

23 CWC ENERGY SERVICES CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS For the three and nine months ended September 30, 2018 and 2017 (unaudited) Three months ended September 30 Nine months ended September 30 Stated in thousands of Canadian dollars Note Operating activities: Net income (loss) $ 326 $ (638) $ (1,545) $ (3,683) Adjustments for: Stock based compensation expense Finance costs ,899 1,448 Depreciation and amortization 4,670 4,512 12,588 12,292 (Gain) loss on disposal of equipment (57) (114) 96 (72) Deferred income tax expense (recovery) 206 (203) (290) (1,143) Funds from operations 6,002 4,055 13,511 9,433 s in non-cash working capital 8 balances (12,097) (6,622) 133 (3,033) Operating cash flow (6,095) (2,567) 13,644 6,400 Investing activities: Purchase of equipment (2,548) (2,409) (9,244) (5,416) Proceeds on disposal of equipment , Investing cash flow (2,482) (2,265) (7,204) (5,246) Financing activities: Increase (repayment) of long-term debt 9,480 5,603 (3,797) 1,193 Interest paid (553) (280) (1,757) (1,248) Finance costs paid (26) (199) (58) (199) Finance lease repayments (74) (49) (227) (166) Common shares issued on exercise of options Common shares purchased under NCIB 7 (205) (296) (690) (672) Financing cash flow 8,622 4,786 (6,381) (977) Increase (decrease) in cash during the period 45 (46) Cash, beginning of period Cash, end of period $ 154 $ 179 $ 154 $ 179 See accompanying notes to the condensed interim consolidated financial statements. Page 21

24 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts 1. Reporting entity CWC Energy Services Corp. ( CWC or the Company ) is incorporated under the Business Corporations Act (Alberta). The address of the Company s head office is Suite 610, 205 5th Avenue SW, Calgary, Alberta, Canada. The Company is an oilfield services company providing drilling and production services to oil and gas exploration and development companies throughout the Western Canadian Sedimentary Basin ( WCSB ). These consolidated financial statements reflect only the Company s proportionate interests in such activities and are comprised of the Company and its subsidiaries. The Company's common stock is listed and traded on the TSX Venture Exchange under the symbol CWC. Additional information regarding CWC s business is available in CWC s most recent Annual Information Form available on SEDAR at on the Company s website or by contacting the Company at the address noted above. 2. Basis of presentation (a) Statement of compliance These condensed interim consolidated financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting and do not include all the information required for full annual financial statements and should be read in conjunction with the annual financial statements of the Company as at and for the year ended December 31, These condensed interim consolidated financial statements were approved by the Board of Directors on October 31, (b) Use of estimates and judgments The preparation of the condensed interim consolidated financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amount of assets and liabilities, income and expense. Actual results may differ from these estimates. In preparing these condensed interim consolidated financial statements, the significant judgments made by management in applying the Company's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the financial statements as at and for the year ended December 31, Significant accounting policies The accounting policies applied by the Company in these condensed interim consolidated financial statements are the same as those applied by the Company in its financial statements as at and for the year ended December 31, 2017, except for the adoption of IFRS 15 Revenue from Contracts with Customers and IFRS 9 Financial Instruments, which were adopted by the Company on January 1, 2018 and are discussed below. These unaudited condensed interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto as at and for the year ended December 31, 2017 as filed on SEDAR. (a) IFRS 15 The Company adopted IFRS 15, Revenue from Contracts with Customers on January 1, The Company reviewed its revenue streams and major contracts with customers using the IFRS 15 five-step model and there were no material Page 22

25 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts changes to net earnings. Under this method, there was no effect to opening deficit from the application of IFRS 15 to revenue contracts in progress at January 1, Revenue recognition policy: Contract Drilling The Company contracts individual drilling rig packages, including crews and support equipment, to its customers. Depending on the customer s drilling program, contracts may be for a single well, multiple wells or fixed term. Revenue from contract drilling services is recognized over time from spud to rig release on a daily basis. Operating days are measured through industry standard tour sheets that document the daily activity of the rig. Revenue is recognized at the applicable day rate for each well, based on rates specified in each contract. Production Services The Company provides a variety of production services including well servicing, coil tubing and swabbing. In general, service rigs, coil tubing units and swabbing rigs do not involve long-term contracts or penalties for termination. Revenue is recognized daily upon completion of services. Operating days are measured through daily tour sheets and field tickets. Revenue is recognized at the applicable daily or hourly rate, as stipulated in the contract. Transition Revenue has been disaggregated into categories based on type of services provided consistent with its reportable operating segments outlined in Note 10. (b) IFRS 9 The Company adopted IFRS 9, Financial Instruments on January 1, The transition to IFRS 9 had no material effect on the Company s financial statements. IFRS 9 contains three principal classification categories for financial assets: measured at amortized cost, fair value through other comprehensive income ( FVOCI ); or fair value through profit or loss ( FVTPL ). The classification of financial assets under IFRS 9 is generally based on the business model in which a financial asset is managed and its contractual cash flow characteristics. IFRS 9 eliminates the previous IAS 39 categories of held to maturity, loans and receivables and available for sale. Under IFRS 9, derivatives embedded in contracts where the host is a financial asset in the scope of the standard are never separated. Instead, the hybrid financial instrument as a whole is assessed for classification. The new standard also introduces an expected credit loss model for evaluating impairment of financial assets, which results in credit losses being recognized earlier than the previous standard. Cash and accounts receivable continue to be measured at amortized cost and are now classified as amortized costs. There was no change to the Company s classification of accounts payable and accrued liabilities or long-term debt. The Company has not designated any financial instruments as FVOCI or FVTPL. (c) Future Accounting Pronouncements IFRS 16, Leases. This standard introduces a single lessee accounting model and requires a lessee to recognize assets and liabilities for all leases with a term of more than 12 months, unless the underlying asset is of low value. A lessee is required to recognize a right-of-use asset representing its right to use the underlying asset and a lease liability representing its obligation to make lease payments. The Company intends to adopt IFRS 16 in its financial statements Page 23

26 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts for the annual period beginning on January 1, The Company has identified leasing contracts and is calculating the impact that the adoption of IFRS 16 may have on its financial statements. 4. Seasonality of operations The Company's operations are located in Western Canada. The ability to move heavy equipment safely and efficiently in Western Canadian oil and natural gas fields is dependent on weather conditions. Activity levels during the first quarter are typically the most robust as the frost creates a stable ground mass that allows for easy access to well sites and easier drilling and service rig movement. The second quarter is traditionally the slowest due to road bans during spring breakup. When winter frost leaves the ground, it renders many secondary roads incapable of supporting the weight of heavy equipment until they have thoroughly dried out. Road bans during this time restrict service and support equipment access to well sites. The third quarter has more activity as the summer months are typically drier than the second quarter. The fourth quarter is again quite active as winter temperatures freeze the ground once more maximizing site access. However, there may be temporary halts to operations in extreme cold weather when the temperature falls below -35C. 5. Property and equipment Contract drilling equipment Production services equipment Other equipment Total Costs Balance, December 31, 2017 $112,478 $256,984 $1,883 $371,345 Additions 6,702 3, ,770 Disposals - (5,824) - (5,824) Balance, September 30, , ,200 1, ,291 Accumulated depreciation and impairment losses Balance, December 31, , ,831 1, ,155 Depreciation 3,958 8, ,361 Disposals - (3,687) - (3,687) Balance, September 30, , ,461 1, ,829 Net book value Balance, September 30, 2018 $94,604 $132,739 $119 $227,462 Additions of property and equipment include purchases of assets under finance lease which are recorded at cost totaling $524. Page 24

27 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts 6. Loans and borrowings The following table provides information with respect to amounts included in the statement of financial position related to loans and borrowings: September 30, 2018 December 31, 2017 Current liabilities: Current portion of finance lease liabilities $ 303 $ 176 Current portion of Mortgage Loan $ 885 $ 176 Non-current liabilities: Bank Loan $ 33,569 $ 50,000 Mortgage Loan 12,073 - Finance lease liabilities Financing fees (468) (531) $ 45,509 $ 49,634 Total loans and borrowings $ 46,394 $ 49,810 The Company has credit facilities with a syndicate of four Canadian financial institutions (the Credit Facility ). During the second quarter of 2018, at the request of the Company, the credit facility was reduced from $100 million to $75 million. The Credit Facility provides the Company with a $75 million extendible revolving term facility (the Bank Loan ) and other credit instruments. Of the Bank Loan, $65 million is a syndicated facility with the remaining $10 million being an operating facility. On August 4, 2017, the Bank Loan was extended for a committed term until July 31, 2020 ( Maturity Date ). No principal payments are required under the Bank Loan until the Maturity Date, at which time any amounts outstanding are due and payable. The Company may, on an annual basis, request the Maturity Date be extended for a period not to exceed three years from the date of the request. If a request for an extension is not approved by the banking syndicate, the Maturity Date will remain unchanged The Bank Loan bears interest based on a sliding scale pricing grid tied to the Company s trailing Consolidated Debt (2) to Consolidated EBITDA (1) ratio from a minimum of the bank s prime rate plus 0.75% to a maximum of the bank s prime rate plus 3.75% or from a minimum of the bankers acceptances rate plus a stamping fee of 1.75% to a maximum of the bankers acceptances rate plus a stamping fee of 4.75%. Standby fees under the Bank Loan range between 0.39% and 1.07%. Interest and fees under the Bank Loan are payable monthly. The Company has the option to borrow funds denominated in either Canadian or United States dollars under the Credit Facility. Borrowings under the Bank Loan are limited to an aggregate of 75% of accounts receivable outstanding less than 90 days plus 60% of the net book value of property and equipment less certain priority payables. As at September 30, 2018, of the $75,000 Bank Loan facility, $36,333 was available for immediate borrowing and $38,667 was outstanding (December 31, 2017: $60,000). The Bank Loan has an accordion feature which provides the Company with an ability to increase the maximum borrowings up to $125,000, subject to the approval of the lenders. The Bank Loan is secured by a security agreement covering all of the assets of the Company and a first charge Security Interest covering all assets of the Company (other than real estate assets related to the Mortgage Loan). Effective September 30, 2018, the applicable rates under the Bank Loan are: bank prime rate plus 1.00%, banker s acceptances rate plus a stamping fee of 2.00%, and standby fee rate of 0.45%. Page 25

28 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts Under the terms of the Credit Facility, the Company is required to comply with the following financial covenants: September 30, Covenant limits 2018 Consolidated Debt (2) to Consolidated EBITDA (1) 4:00: 1.00 or less 1.35:1.00 Consolidated Debt (2) to Capitalization (3) 0.50:1.00 or less 0.15:1.00 Consolidated Adjusted Cash Flow (4) to Consolidated Finance Obligations (5) 1.15:1.00 or more 7:54:1.00 (1) Consolidated EBITDA is calculated as net income plus finance costs, plus current and deferred income taxes, plus depreciation, plus stock based compensation, plus any non-recurring losses or impairment losses, or permitted severance costs, minus any non-recurring gain, plus any expenses related to corporate or business acquisitions with all amounts being for the twelve month period ended the calculation date. EBITDA is adjusted to reflect the inclusion of material acquisitions or material dispositions on a pro forma basis for the twelve month period ended the calculation date. Consolidated EBITDA is increased if debt repayments from the proceeds of equity issuance are used to repay the syndicated facility and designated by the Company as an Equity Cure amount. (2) Consolidated Debt is calculated as total loans and borrowings as shown in the schedule above adjusted to exclude the funds held in the segregated account and to remove any financing fees included. (3) Capitalization is calculated as Consolidated Debt plus Shareholders Equity as at the calculation date. (4) Consolidated Adjusted Cash Flow is calculated as Consolidated EBITDA minus amounts paid for transaction costs, dividends or share repurchases in the twelve month period ended the calculation date. The Calculation of Adjusted Cash Flow excludes Consolidated EBITDA resulting from an Equity Cure. (5) Consolidated Finance Obligations is calculated as finance costs plus scheduled principal payments on debt including scheduled principal payments under finance leases minus accretion of finance fees included in finance costs for the twelve month period ended the calculation date. On December 18, 2017, the Company received gross proceeds of $26,000 from a rights offering of common shares of which $10,000 was placed in a segregated bank account. On July 5, 2018, $5,000 was paid on the Bank Loan. Additionally on October 5, 2018 the remaining $5,098 held in the segregated account was paid on the Bank Loan. Consolidated Debt to Consolidated EBITDA at September 30, 2018 includes the impact of a $10,098 equity cure designated on July 5, 2018 and October 5, Mortgage Loan is a loan maturing on June 28, 2023 that is amortized over 22 years with blended monthly principal and interest payments of $86. At maturity, approximately $9,891 of principal will become payable assuming only regular monthly payments are made. On July 27, 2018 the Company entered into an interest rate swap to exchange the floating rate interest payments for fixed rate interest payments, which fix the Bankers Acceptance-Canadian Dollar Offered Rate components of its interest payment on the outstanding term debt. Under the interest rate swap agreement, the Company pays a fixed rate of 2.65% per annum plus the applicable credit spread of 1.35%, for an effective fixed rate of 4.0%. The fair value of the interest rate swap arrangement is the difference between the forward interest rates and the discounted contract rate. As of September 30, 2018 the mark-to-market value of the interest rate swap was nominal. Obligations under finance leases are primarily for leased automobiles with an expected term of three years and a one year minimum term. Interest rates on finance leases are specific to each leased asset, are fixed for the lease term and vary between 4.4% and 5.9% per annum. Financing fees consist of commitment fees and legal expenses relating to the Credit Facility and are being amortized using the effective interest rate method over the term of the Credit Facility. Financing fees of $120 were amortized and included in finance costs during the nine months ended September 30, 2018 (year ended December 31, 2017: $242). Page 26

29 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts The following table summarizes the balances of long-term debt: September 30, 2018 Cash Long-term debt Net Gross amounts 5,098 (50,607) (45,509) Amount offset (5,098) 5,098 - Net amounts - (45,509) (45,509) 7. Share capital (a) Authorized Unlimited number of Common voting shares without par value. Unlimited number of Preferred shares without par value. (b) Normal course issuer bid On April 10, 2018, the Company replaced its expired Normal Course Issuer Bid (NCIB) with a new NCIB which now expires on April 9, Under the new NCIB the Company may purchase, from time to time as it considers advisable, up to 26,057,889 of issued and outstanding common shares through the facilities of the TSXV or other recognized marketplaces. In addition, CWC entered into an automatic securities purchase plan (the ASPP ) (as defined under applicable securities laws) with Raymond James Ltd. ("Raymond James") for the purpose of making purchases under the ASPP. Such purchases will be determined by Raymond James in its sole discretion, without consultation with CWC having regard to the price limitation and aggregate purchase limitation and other terms of the ASPP and the rules of the TSXV. Conducting the NCIB as an ASPP allows common shares to be purchased at times when CWC would otherwise be prohibited from doing so pursuant to securities laws and its internal trading policies. For the three months ended September 30, 2018, 1,175,500 shares (three months ended 2017: 1,404,000) for consideration of $205 including commissions (2017: $296) were purchased under the NCIB, and for the nine months ended September 30, 2018, 3,593,000 shares (nine months ended 2017: 3,088,500) for consideration of $690 including commissions (2017: $672) were purchased under the NCIB. In the three months ended September 30, 2018, a total of 1,309,000 shares were cancelled and returned to treasury (2017: 1,441,500), and in the nine months ended September 30, 2018, a total of 3,563,000 shares were cancelled and returned to treasury (2017: 3,088,500). Page 27

30 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts (c) Stock options The following table summarizes changes in the number of stock options outstanding: Weighted Number of options average exercise price Balance at December 31, ,546,667 $ 0.25 Exercised for common shares (1,033,335) 0.14 Expired (2,161,999) 0.31 Balance at September 30, ,351,333 $ 0.25 For the three months ended September 30, 2018, stock-based compensation expense relating to stock options totaled $157 (three months ended September 30, 2017: $111). For the nine months ended September 30, 2018, stock-based compensation expense relating to stock options totaled $509 (nine months ended September 30, 2017: $411). (d) Restricted share unit plan The following table summarizes information about RSUs outstanding as at September 30, 2018: Weighted average exercise price Weighted average Issue date fair value Number of RSUs outstanding remaining life (years) contractual ($) $ ,579, n/a 632,332 Number of RSUs exercisable For the three months ended September 30, 2018, stock-based compensation expense relating to RSUs totaled $84 (three months ended September 30, 2017: $54). For the nine months ended September 30, 2018, stock-based compensation expense relating to RSUs totaled $254 (nine months ended September 30, 2017: $180). For the nine months ended September 30, 2018, 305,667 RSUs were exercised (2017: 600,833), 304,333 RSUs were forfeited (2017: 200,000) and 54,000 RSUs were issued (2017: 75,000). (e) Weighted average common shares outstanding The following table reconciles the common shares used in computing per share amounts for the periods noted: For the three months ended September 30, For the nine months ended September 30, Weighted average common shares outstanding basic 520,463, ,704, ,271, ,301,224 Effect of dilutive share-based compensation plans 4,290, Weighted average common shares outstanding basic and diluted 524,754, ,704, ,271, ,301,224 Page 28

31 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts Outstanding stock options and RSUs are currently the only instruments which could potentially dilute earnings per share. For the nine months ended September 30, 2018, the effect of all outstanding stock options and RSUs were not included in the computation of net income (loss) per common share because to do so would be anti-dilutive. 8. Supplemental cash flow information For the three months ended September 30, For the nine months ended September 30, Increase (decrease) in non-cash working capital items: Accounts receivable $(9,376) $ (7,532) $1,914 $ (4,647) Prepaid expenses and deposits (199) 371 (132) 478 Accounts payable and accrued liabilities (2,522) 539 (1,649) 1,136 $(12,097) $ (6,622) $133 $ (3,033) 9. Operating segments The Company operates in the western Canadian oilfield service industry through its Contract Drilling and Production Services segments. The Contract Drilling segment provides drilling rigs and related ancillary equipment to oil and gas exploration and production companies. The Production Services segment provides well services to oil and gas exploration and production companies through the use of service rigs, swabbing rigs and coil tubing units. Management uses net income before depreciation and income taxes ( segment profit ) in management reports reviewed by key management personnel and the board of directors to measure performance at a segment basis. Segment profit is used to measure performance as management believes this is the most relevant measure in evaluating the results of our segments relative to each other and other entities that operate within the respective industries. The Corporate segment captures general and administrative expenses associated with supporting each of the reporting segments operations, plus costs associated with being a public company. Also included in the Corporate segment is interest expense for debt servicing, income tax expense and other amounts not directly related to the two primary segments. Page 29

32 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts The amounts related to each industry segment are as follows: For the three months ended September 30, 2018 Contract Drilling Production Services Corporate Total Revenue $ 10,634 $ 27,479 $ - $ 38,113 Direct operating expenses 8,311 19,635-27,946 Selling and administrative expenses 311 2,456 1,398 4,165 Stock based compensation Finance costs Gain on disposal of equipment - (57) - (57) Net income (loss) before depreciation and taxes 2,012 5,445 (2,255) 5,202 Depreciation and amortization 1,818 2, ,670 Net income (loss) before tax 194 2,809 (2,471) 532 Deferred income tax expense Net income (loss) $ 194 $ 2,809 $ (2,677) $ 326 Capital expenditures $ 1,586 $ 1,110 $ - $ 2,696 As at September 30, 2018 Property and equipment $ 94,604 $ 132,739 $ 119 $ 227,462 Intangibles $ 191 $ - $ - $ 191 For the three months ended September 30, 2017 Contract Drilling Production Services Corporate Total Revenue $ 10,130 $ 17,043 $ - $ 27,173 Direct operating expenses 7,233 12,726-19,959 Selling and administrative expenses 243 1, ,159 Stock based compensation Finance costs Gain on disposal of equipment - (114) - (114) Net income (loss) before depreciation and taxes 2,654 2,487 (1,470) 3,671 Depreciation and amortization 1,830 2, ,512 Net income (loss) before tax 824 (156) (1,509) (841) Deferred income tax recovery - - (203) (203) Net income (loss) $ 824 $ (156) $ (1,306) $ (638) Capital expenditures $ 1,504 $ 1,040 $ - $ 2,544 As at September 30, 2017 Property and equipment $ 92,581 $ 92,004 $ 214 $ 184,799 Intangibles $ 495 $ - $ - $ 495 Page 30

33 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts For the nine months ended September 30, 2018 Contract Drilling Production Services Corporate Total Revenue $ 25,143 $ 84,140 $ - $ 109,283 Direct operating expenses 19,087 63,109 82,196 Selling and administrative expenses 960 8,102 4,514 13,576 Stock based compensation Finance costs - - 1,899 1,899 Loss on disposal of equipment Net income (loss) before depreciation and taxes 5,096 12,833 (7,176) 10,753 Depreciation and amortization 4,194 7, ,588 Net income (loss) before tax 902 5,104 (7,841) (1,835) Deferred income tax recovery - - (290) (290) Net income (loss) $ 902 $ 5,104 $ (7,551) $ (1,545) Capital expenditures $ 6,702 $ 3,040 $ 28 $ 9,770 For the nine months ended September 30, 2017 Contract Drilling Production Services Corporate Total Revenue $ 24,308 $ 50,487 $ - $ 74,795 Direct operating expenses 17,664 38,077-55,741 Selling and administrative expenses 677 6,102 2,842 9,621 Stock based compensation Finance costs - - 1,448 1,448 Loss (Gain) on disposal of equipment 48 (120) - (72) Net income (loss) before depreciation and taxes 5,919 6,428 (4,881) 7,466 Depreciation and amortization 4,242 7, ,292 Net income (loss) before tax 1,677 (1,501) (5,002) (4,826) Deferred income tax recovery - - (1,143) (1,143) Net income (loss) $ 1,677 $ (1,501) $ (3,859) $ (3,683) Capital expenditures $ 2,788 $ 2,829 $ 9 $ 5,626 Page 31

34 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts 10. Revenue Revenue consists of amounts earned from sale of Contract Drilling and Production Services. Production Services includes revenue from service rigs, coil tubing and swabbing rigs. The transaction terms for drilling services provided by Contract Drilling, are based on standard Canadian Association of Oilwell Drilling Contractors ( CAODC ) contracts, whereas transaction terms for Production Services are agreed to on a contract by contract basis by both the Company and customers. For both Contract Drilling and Production Services, the customer receives benefit from each day of active service and as such the performance obligation. Contract Drilling revenue includes day work revenue, standby revenue, moving revenue and third party revenue. Production Services include hourly work revenue and moving revenue. For both Contract Drilling and Production Services, the customer receives benefit from each day of active services and as such the performance obligation requested to recognize revenue occurs daily based on contract pricing. The Company s revenue is primarily generated in Western Canada. The customers are oil and natural gas producers and are subject to normal credit risks. The Company routinely assesses the financial strength of its counterparties. The following table presents the Company s revenue disaggregated by type: For the three months ended September 30, For the nine months ended September 30, Contract Drilling $ 10,634 $ 10,130 $ 25,143 $ 24,308 Production Services Service and Swabbing Rigs 26,822 15,817 80,381 46,155 Coil Tubing 657 1,226 3,759 4,332 $ 38,113 $ 27,173 $ 109,283 $ 74,795 Included in accounts receivable at September 30, 2018 was $3,826 (December 31, 2017: $2,322) of accrued revenue for services provided in the month then ended. There have been no significant adjustments for prior period accrued revenue in the current period. As of September 30, 2018, the Company did not have any sales contracts beyond one year in term. For the quarter ended September 30, 2018, ten customers comprised 59% of revenue (Year ended December 31, %) and one customer comprised 21% of revenue (Year ended December 31, %). Page 32

35 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts 11. Expenses by nature Direct Selling and For the three months operating administrative Stock based Finance Depreciation Gain on disposal ended September 30, 2018 expenses expenses compensation costs expense of equipment Total Personnel expenses $ 18,824 $ 2,656 $ 241 $ - $ - $ - $ 21,721 Third party charges 3,806 3,806 Repairs and maintenance 5,316 5,316 Other selling and administrative expenses Bad debt expense Facility expenses Depreciation expense 4,670 4,670 Finance costs Gain on disposal of equipment (57) (57) Total $ 27,946 $ 4,165 $ 241 $ 616 $ 4,670 $ (57) $ 37,581 Direct Selling and For the three months operating administrative Stock based Finance Depreciation Gain on disposal ended September 30, 2017 expenses expenses compensation costs expense of equipment Total Personnel expenses $ 14,083 $ 1,780 $ 165 $ - $ - $ - $ 16,028 Third party charges 2, ,831 Repairs and maintenance 3, ,045 Other selling and administrative expenses Bad debt expense Facility expenses Depreciation expense ,512-4,512 Finance costs Gain on disposal of equipment (114) (114) Total $ 19,959 $ 3,159 $ 165 $ 333 $ 4,512 $ (114) $ 28,014 Page 33

36 CWC ENERGY SERVICES CORP. NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS As at and for the three and nine months ended September 30, 2018 and 2017 (unaudited) Stated in thousands of Canadian dollars except share and per share amounts Direct Selling and Loss on For the nine months ended operating administrative Stock based Finance Depreciation disposal of September 30, 2018 expenses expenses compensation costs expense equipment Total Personnel expenses $ 54,950 $ 8,204 $ 763 $ - $ - $ - $ 63,917 Third party charges 12, ,781 Repairs and maintenance 14, ,465 Other selling and administrative expenses - 3, ,197 Bad debt expense Facility expenses - 1, ,801 Depreciation expense ,588-12,588 Finance costs , ,899 Loss on disposal of equipment Total $ 82,196 $ 13,576 $ 763 $ 1,899 $ 12,588 $ 96 $111,118 Direct Selling and Gain on For the nine months ended operating administrative Stock based Finance Depreciation disposal of September 30, 2017 expenses expenses compensation costs expense equipment Total Personnel expenses $ 38,353 $ 5,596 $ 591 $ - $ - $ - $ 44,540 Third party charges 10, ,708 Repairs and maintenance 6, ,680 Other selling and administrative expenses - 2, ,543 Bad debt expense Facility expenses - 1, ,459 Depreciation expense ,292-12,292 Finance costs , ,448 Gain on disposal of equipment (72) (72) Total $ 55,741 $ 9,621 $ 591 $ 1,448 $ 12,292 $ (72) $ 79, Comparative figures Certain comparative figures have been reclassified to conform with the financial statement presentation adopted for the current year. Page 34

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39 Corporate Secretary Audit Committee Compensation and Corporate Governance Committee Ernst & Young LLP Bankers Duncan Au, CPA, CA, CFA President & Chief Executive Of icer Stuart King, CPA, CA Chief Financial Of icer Paul Donohue Vice President Operations (Drilling) Darwin McIntyre Vice President Operations (Well Services) Bob Apps Vice President, Sales and Marketing (Drilling) Mike Dubois Vice President, Sales and Marketing (Well Services) Cover page photo courtesy of Rob Berg CWC-2018Q1d.indd :39 PM

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