CALGARY, Feb. 28, 2018 /CNW/ – Whitecap Resources Inc. (“Whitecap” or the “Company”) (TSX: WCP) is pleased to report its operating and audited financial results for the year ended December 31, 2017.
Selected financial and operating information is outlined below and should be read with Whitecap’s audited annual consolidated financial statements and related Management’s Discussion and Analysis (“MD&A”) and Annual Information Form (“AIF”) which are available at www.sedar.com and on our website at www.wcap.ca.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended December 31 |
Twelve months ended December 31 |
||||
Financial ($000s except per share amounts) |
2017 |
2016 |
2017 |
2016 |
|
Petroleum and natural gas sales |
285,009 |
209,149 |
1,001,343 |
635,306 |
|
Net income (loss) |
(231,729) |
191,104 |
(123,968) |
170,748 |
|
Basic ($/share) |
(0.61) |
0.52 |
(0.33) |
0.50 |
|
Diluted ($/share) |
(0.61) |
0.51 |
(0.33) |
0.50 |
|
Funds flow (1) |
143,543 |
117,792 |
508,627 |
384,725 |
|
Basic ($/share) (1) |
0.38 |
0.32 |
1.37 |
1.13 |
|
Diluted ($/share) (1) |
0.38 |
0.32 |
1.36 |
1.13 |
|
Dividends paid or declared |
27,476 |
25,745 |
104,926 |
116,521 |
|
Per share |
0.07 |
0.07 |
0.28 |
0.35 |
|
Total payout ratio (%) (1) |
59 |
89 |
87 |
76 |
|
Development capital (1) |
57,162 |
79,651 |
338,780 |
173,993 |
|
Property acquisitions |
939,015 |
12,043 |
970,883 |
630,565 |
|
Property dispositions |
(8,777) |
35 |
(14,598) |
(144,379) |
|
Net debt (1) |
1,295,906 |
818,580 |
1,295,906 |
818,580 |
|
Operating |
|||||
Average daily production |
|||||
Crude oil (bbls/d) |
44,699 |
37,072 |
43,589 |
32,398 |
|
NGLs (bbls/d) |
3,634 |
3,247 |
3,415 |
3,168 |
|
Natural gas (Mcf/d) |
68,244 |
61,756 |
62,676 |
61,651 |
|
Total (boe/d) |
59,707 |
50,612 |
57,450 |
45,841 |
|
Average realized price (2) |
|||||
Crude oil ($/bbl) |
63.60 |
53.88 |
57.28 |
47.58 |
|
NGLs ($/bbl) |
37.22 |
23.60 |
30.44 |
17.31 |
|
Natural gas ($/Mcf) |
1.75 |
3.23 |
2.27 |
2.26 |
|
Total ($/boe) |
51.89 |
44.92 |
47.75 |
37.87 |
|
Netbacks ($/boe) |
|||||
Petroleum and natural gas sales before tariffs (1) |
53.04 |
46.81 |
49.18 |
39.92 |
|
Tariffs (1) |
(1.15) |
(1.89) |
(1.43) |
(2.05) |
|
Realized hedging gain (loss) |
(2.19) |
1.65 |
(1.15) |
4.44 |
|
Royalties |
(7.41) |
(6.89) |
(6.89) |
(5.42) |
|
Operating expenses |
(10.88) |
(10.18) |
(10.61) |
(9.54) |
|
Transportation expenses |
(1.93) |
(1.00) |
(1.63) |
(0.89) |
|
Operating netbacks (1) |
29.48 |
28.50 |
27.47 |
26.46 |
|
General and administrative expenses |
(1.29) |
(1.15) |
(1.31) |
(1.29) |
|
Interest and financing expenses |
(1.87) |
(1.91) |
(1.77) |
(2.14) |
|
Transaction costs |
(0.02) |
– |
– |
(0.02) |
|
Settlement of decommissioning liabilities |
(0.16) |
(0.14) |
(0.13) |
(0.07) |
|
Funds flow netbacks (1) |
26.14 |
25.30 |
24.26 |
22.94 |
|
Share information (000s) |
|||||
Common shares outstanding, end of period |
418,029 |
368,351 |
418,029 |
368,351 |
|
Weighted average basic shares outstanding |
379,326 |
368,272 |
371,848 |
339,735 |
|
Weighted average diluted shares outstanding |
381,574 |
371,193 |
373,944 |
341,893 |
Notes: |
|
(1) |
Funds flow, funds flow per share, total payout ratio, development capital, net debt, petroleum and natural gas sales before tariffs, tariffs, operating netbacks and funds flow netbacks do not have a standardized meaning under GAAP. Refer to non-GAAP measures in this press release for additional disclosure and assumptions. |
(2) |
Prior to the impact of hedging activities. |
MESSAGE TO SHAREHOLDERS
We are pleased to report another year of significant growth and long-term value creation for our Company in 2017. As a result of our continued pursuit of operational excellence, we were able to achieve strong operational results in a safe and environmentally responsible manner and also able to deliver robust financial results. We concluded the year with the acquisition of the world class Weyburn CO2 enhanced oil recovery project in southeast Saskatchewan (the “Weyburn Acquisition”) that will provide substantial free funds flow and incremental value for Whitecap shareholders for many years to come.
In 2017, we allocated 66% of our funds flow to grow production organically by 15% per share and used 21% of our funds flow to return cash to shareholders through our cash dividend program. This resulted in a total payout ratio of 87% and $64.9 million of free funds flow which was used to reduce bank debt. Our development capital program included the drilling of 227 (193.6 net) horizontal oil wells. Whitecap’s development capital program resulted in finding and development (“F&D”) costs on proved developed producing (“PDP”) reserves of $11.25/boe, including future development capital (“FDC”), a reduction of 22% compared to the prior year. This resulted in a very strong PDP recycle ratio of 2.4 times.
With respect to our business development initiatives, in December we were able to complete the Weyburn Acquisition for $940 million which included net production of 14,800 boe/d (100% light oil) with a low base decline rate and significant incremental growth and expansion opportunities. The acquisition is a continuation of our long-term strategy to focus on high netback, low decline assets that have the ability to grow production within their own funds flow. We anticipate this asset to not only grow production on an annual basis but to also provide significant free funds flow well into the future.
2017 FINANCIAL HIGHLIGHTS
- Achieved record annual production of 57,450 boe/d in 2017 despite significant unexpected third party facility downtime in Q2/17. Annual production increased 25% or 15% per fully diluted share compared to the prior year.
- Q4/17 production was 59,707 boe/d and impacted by approximately 500 boe/d due to extreme cold weather in the last week of December and the disposition of non-core production for $22 million. Despite the foregoing, Q4/17 average production increased 18% or 15% per fully diluted share compared to Q4/16.
- Development capital spending was $338.8 million in 2017 of which $3.0 million was spent on the Weyburn assets. We drilled a total of 227 (193.6 net) oil wells including 125 (115.2 net) horizontal Viking oil wells in west central Saskatchewan, 32 (28.6 net) horizontal Cardium wells in west central Alberta, 38 (24.4 net) wells in southwest Saskatchewan, 6 (4.1 net) horizontal Dunvegan wells and 17 (12.6 net) horizontal Cardium wells at Wapiti in northwest Alberta, 6 (5.7 net) Boundary Lake (Triassic) wells in British Columbia, and 3 (3.0 net) wells at Elnora.
- Supported by strong operational execution, stronger crude oil prices and free funds flow, we increased our dividend by 5% in 2017 and paid out $104.9 million of cash dividends to shareholders in the year. Whitecap generated $508.6 million of funds flow in 2017 which exceeded development capital spending and dividend payments by $64.9 million, resulting in a total payout ratio of 87%. Funds flow per share was $1.36 per fully diluted share compared to $1.13 per fully diluted share in 2016, an increase of 20%.
- On the business development front, as outlined earlier, Whitecap closed the Weyburn Acquisition for $940 million on December 14, 2017. The acquisition significantly enhances Whitecap’s free funds flow profile and reduces our base decline rate from 23% to 19% which provided us with the confidence to increase our dividend by an additional 5% in January 2018. Refer to our press release dated November 13, 2017 for further details.
- Whitecap’s balance sheet remains strong with year end net debt of $1.3 billion on a total credit facility of $1.7 billion, leaving significant unutilized credit capacity for financial flexibility. Of the $1.3 billion net debt at year end, $595 million was termed out with 5, 7 and 9 year terms at a very attractive blended average long-term interest rate of 3.63%. Our optimized capital structure reflects the stability of our low decline production base and the long reserve life characteristic of our asset base.
- In addition to double-digit production per share growth, increasing the monthly dividend, closing on an accretive acquisition, shareholder returns were also enhanced by $10.5 million of share buybacks in 2017 which reduced our common shares outstanding by 1.2 million shares.
2017 OPERATIONAL HIGHLIGHTS
- The Viking program continues to deliver excellent capital efficiencies highlighted by our standard length and extended reach horizontal (“ERH”) well productivity. To balance the high production growth rate, we continue to flatten our base declines by re-developing and expanding our existing waterfloods in Eagle Lake and Kerrobert. In Kerrobert, we have seen encouraging response from the 18 injector conversions done in 2017, of which 4 were horizontals, which added 2,200 barrels of water per day of targeted injection support. In Eagle Lake, 5 injector conversions coupled with significant optimization of the existing injectors has resulted in improving pressure support for our infill wells which are exhibiting lower declines and averaging 40,000 barrels of oil in their first year of production.
- Our SW Saskatchewan assets, purchased in June 2016, continue to perform above our initial expectations. To date we have drilled 27 (19.3 net) horizontal oil wells in the Atlas (Cantaur) resource play and the results have provided us with the confidence to increase our type curves by 14% in 2017. In addition, we continue to make inroads on optimizing our operating costs which averaged $13.78/boe in 2017 compared to $16.71 at the time of acquisition.
- The Cardium program in west central Alberta was focused on the redevelopment of our legacy waterfloods in West Pembina. Our un-fractured horizontal injector is still performing extremely well and has injected cumulatively 40,000 barrels of water over its first 8 months of injection. We will be drilling an additional injection well as a follow up to this injector in Q1/18. We anticipate this pilot injector design will be integrated into the full development of the pool resulting in a savings of over $14 million or a 13% reduction in the total development cost estimate.
- In the Deep Basin, we have been focused on the continued advancement of the Wapiti Cardium development spending 65% of the Deep Basin’s total development capital budget. We continue to refine fracture design and well placement, which resulted in a further 30% increase in initial production rates when compared to earlier designs. We have over 163 (95.8 net) remaining undrilled locations at Wapiti on which to apply these learnings and 50% of these locations are not contained in our reserve report.
2017 RESERVES HIGHLIGHTS
The 2017 capital program focused on continuing to reduce our base production decline rate which, in turn, enhanced our ability to grow production per share, pay a sustainable and growing dividend and also generate significant free funds flow. The effective execution of this strategy with our development capital program has resulted in exceptional PDP reserve bookings and strong overall results from our reserves evaluation.
Proved Developed Producing (“PDP”)
- Development capital spending replaced 126% of production at an F&D cost of $11.25/boe which generated a recycle ratio of 2.4 times.
- Increased PDP reserves by 49% or 31% per fully diluted share to 222.1 MMboe from 149.0 MMboe in 2016.
- Total PDP reserve additions of 94.0 MMboe replaced 449% of production at an FD&A cost of $21.68/boe, including FDC, which results in a recycle ratio of 1.3 times.
- PDP reserves represent 64% of the TP reserves compared to 59% in the prior year.
Total Proved (“TP”)
- Development capital spending replaced 115% of production at an F&D cost of $13.37/boe, including changes in FDC, which generated a recycle ratio of 2.1 times.
- Increased TP reserves by 38% or 21% per fully diluted share to 347.0 MMboe from 251.8 MMboe in 2016.
- Total reserve additions of 116.2 MMboe replaced 555% of production at an FD&A cost of $21.53/boe, including FDC, which results in a recycle ratio of 1.3 times.
- TP reserves comprise 72% of TPP reserves compared to 71% in the prior year.
Total Proved Plus Probable (“TPP”)
- Development capital spending replaced 124% of production at an F&D cost of $12.66/boe, including changes in FDC, which generated a recycle ratio of 2.2 times.
- Increased TPP reserves by 36% or 19% per fully diluted share to 482.9 MMboe from 355.8 MMboe in 2016.
- Total TPP reserve additions of 148.0 MMboe replaced 707% of production at an FD&A cost of $17.05/boe, including FDC, which results in a recycle ratio of 1.6 times.
- Net asset value based on total proved plus probable (“TPP”) reserves discounted at 10% is $12.50 per fully diluted share. Net present value of reserves is adjusted for net debt of $1.3 billion and undeveloped land value of $70.1 million.
OUTLOOK
Whitecap’s business strategy has been built on operational excellence to deliver predictable performance focused on per share growth on our high quality assets in order to provide top decile economic returns and sustainable total shareholder returns annually.
Our priorities continue to include (1) maintaining a strong balance sheet, (2) generating strong production and funds flow per share growth, (3) paying a sustainable and growing dividend, and (4) continued commitment to strong safety and responsible environmental standards.
We have experienced improving crude oil prices in 2018 with current prices above WTI US$60 per barrel, however, we expect to see continuing volatility as we move through the year. Even with the higher prices today, our strategy remains unchanged and we remain committed to demonstrating predictable operational and financial performance to drive superior returns through fluctuating commodity price cycles. We are on track to deliver another year of double digit production per share growth and anticipate funds flow to once again exceed capital expenditures and dividend payments. Our robust hedge portfolio provides significant downside protection and, as with previous years, we anticipate a total payout ratio of less than 100% in 2018 even with crude oil prices below WTI US$45 per barrel. We are also highly levered towards an improving crude oil price environment as we are 86% weighted towards oil and natural gas liquids.
Whitecap is well positioned to provide industry-leading production per share growth while generating substantial free funds flow given our lower base decline rate of 19%, high funds flow netbacks, and strong capital efficiencies. This provides us with optionality in 2018 to redeploy the free funds flow towards debt repayment, increasing our dividend, share buybacks or to fund future acquisitions without the issuance of equity while still maintaining a strong balance sheet.
In 2017, we delivered on our financial and operational metrics while also achieving a very strong health, safety and environmental record. We remain committed to demonstrating leadership on health, safety and the environment and will focus on increasing the transparency of our disclosures to our shareholders in 2018.
We are also pleased to announce, as part of our ongoing commitment to strong corporate governance, the appointment of Ken Stickland as Chairman of the Board of Directors. Mr. Stickland has been a valued member of Whitecap’s Board of Directors since 2013 and has a strong legal and governance background, along with extensive experience in the energy sector at both the senior executive and board levels.
On behalf of our board of directors and the Whitecap management team, we would like to thank our shareholders for their ongoing support and look forward to providing strong financial and operational updates as we progress through 2018.
2017 RESERVES REVIEW
Our 2017 year end reserves were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”) and GLJ Petroleum Consultants (“GLJ”) in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2017. The reserves evaluation was based on McDaniel’s forecast pricing and foreign exchange rates at January 1, 2018 which is available on their website at www.mcdan.com.
Reserves included are Company share reserves which are the Company’s total working interest reserves before the deduction of any royalties and include any royalty interests payable to the Company. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR on or before March 31, 2017. The numbers in the tables below may not add due to rounding.
Summary of Reserves
Whitecap was once again able to deliver both absolute and per share reserves growth in all categories in 2017. Compared to the prior year, PDP, TP and TPP reserves increased 49%, 38% and 36% or 31%, 21% and 19% per fully diluted share, respectively.
Reserves |
||||
As at December 31, 2017 |
||||
Company Share Reserves |
||||
Description |
Oil (Mbbl) |
Gas (MMcf) |
NGL (Mbbl) |
Total (Mboe) |
Proved producing |
178,472 |
192,419 |
11,542 |
222,084 |
Proved non-producing |
3,037 |
4,887 |
98 |
3,949 |
Proved undeveloped |
94,875 |
111,010 |
7,633 |
121,009 |
Total proved |
276,384 |
308,315 |
19,272 |
347,042 |
Probable |
104,297 |
135,352 |
9,021 |
135,877 |
Total proved plus probable |
380,681 |
443,667 |
28,293 |
482,919 |
Net Present Values
Before tax net present value discounted 10% per share increased 8% to $15.37 per share on TPP reserves and 6% to $11.04 per fully diluted share on TP reserves despite a 6% decrease to the 5 year average Edmonton light price forecast and a 16% decrease to the 5 year average AECO price forecast.
Summary of Before Tax Net Present Values |
|||||||||||
(Forecast Pricing) |
|||||||||||
As at December 31, 2017 |
|||||||||||
Before Tax Net Present Value ($MM) (1) |
|||||||||||
Discount Rate |
|||||||||||
Description |
0% |
5% |
10% |
15% |
20% |
||||||
Proved producing |
5,665 |
4,159 |
3,257 |
2,682 |
2,290 |
||||||
Proved non-producing |
129 |
90 |
67 |
53 |
44 |
||||||
Undeveloped |
3,185 |
2,010 |
1,349 |
950 |
692 |
||||||
Total proved |
8,979 |
6,259 |
4,674 |
3,686 |
3,025 |
||||||
Probable |
5,714 |
2,927 |
1,831 |
1,292 |
983 |
||||||
Total proved plus probable |
14,694 |
9,186 |
6,505 |
4,978 |
4,009 |
||||||
Per fully diluted share |
$34.72 |
$21.71 |
$15.37 |
$11.76 |
$9.47 |
||||||
(1) Includes abandonment and reclamation costs as defined in NI 51-101. |
Future Development Costs
FDC reflects the best estimate of the capital cost to produce reserves. FDC associated with our TPP reserves at year end 2017 is $2.2 billion and includes Polymer and CO2 purchases for our southwest and southeast Saskatchewan enhanced oil recovery projects. TPP FDC for these two items is $680 million undiscounted ($301 million discounted 10%) and TP FDC is $668 million undiscounted ($301 million undiscounted 10%).
Also included in FDC are 1,297 (1,052.9 net) booked locations of which 455 (391.9 net) are ERH. Booked locations represent 47% of Whitecap’s total inventory at December 31, 2017 of 2,897 (2,251.7 net) locations of which 850 (711.7 net) are ERH wells.
($000s) |
Total Proved |
Total Proved plus Probable |
2018 |
546,414 |
551,494 |
2019 |
565,098 |
594,083 |
2020 |
469,374 |
556,887 |
2021 |
349,145 |
397,156 |
2022 |
203,843 |
233,532 |
Remainder |
758,264 |
817,139 |
Total FDC, Undiscounted |
2,892,138 |
3,150,290 |
Total FDC, Discounted at 10% |
1,982,988 |
2,155,262 |
Performance Measures
Highlights to our 2017 performance measures include very strong F&D costs as well as F&D recycle ratios above 2 times in each of the PDP, TP and TPP reserve categories. FD&A costs for the year were consistent with the 3 year average and reflect the long life, light oil, high netback acquisition of the Weyburn assets. 2016 had unusually low F&D and associated FD&A due to a significant correction in services costs which resulted in a one-time downward revision to FDC.
We were also able to drive record production replacement of produced reserves for PDP at 449%, TP at 555% and TPP at 707%. These exceptionally strong ratios on our high quality assets have extended our reserve life index to 10.2 years on PDP reserves, 15.9 years on TP reserves, and 22.2 years on TPP reserves.
The following table highlights annual performance ratios based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel and GLJ:
2017 |
2016 |
2015 |
Three Year |
||
Proved Developed Producing |
|||||
F&D costs (1) |
$11.25 |
$14.46 |
$12.57 |
$12.60 |
|
F&D recycle ratio (2) |
2.4x |
1.8x |
2.9x |
2.3x |
|
FD&A costs (3) |
$21.68 |
$15.78 |
$29.46 |
$21.74 |
|
FD&A recycle ratio (2) |
1.3x |
1.7x |
1.2x |
1.4x |
|
Production replacement (4) |
449% |
313% |
236% |
353% |
|
RLI (years) (5) |
10.2 |
8.1 |
7.4 |
8.8 |
|
Total Proved |
|||||
F&D costs (1) |
$13.37 |
$2.42 |
$8.86 |
$8.76 |
|
F&D recycle ratio (2) |
2.1x |
10.9x |
4.1x |
5.4x |
|
FD&A costs (3) |
$21.53 |
$13.32 |
$23.11 |
$19.31 |
|
FD&A recycle ratio (2) |
1.3x |
2.0x |
1.6x |
1.6x |
|
Production replacement (4) |
555% |
409% |
400% |
470% |
|
RLI (years) (5) |
15.9 |
13.6 |
13.0 |
14.4 |
|
Total Proved Plus Probable |
|||||
F&D costs (1) |
$12.66 |
$2.34 |
$6.97 |
$7.95 |
|
F&D recycle ratio (2) |
2.2x |
11.3x |
5.2x |
5.8x |
|
FD&A costs (3) |
$17.05 |
$11.51 |
$18.27 |
$15.59 |
|
FD&A recycle ratio (2) |
1.6x |
2.3x |
2.0x |
1.9x |
|
Production replacement (4) |
707% |
559% |
499% |
608% |
|
RLI (years) (5) |
22.2 |
19.3 |
18.2 |
20.3 |
(1) |
F&D costs are calculated as the sum of field capital of $330.1 million plus the change in FDC for the period of -$32.5 million (PDP), -$8.1 million (TP) and -$1.4 million (TPP), divided by the change in reserves that are characterized as development for the period. |
(2) |
Recycle ratio is calculated as operating netback divided by F&D or FD&A costs. Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties, operating expenses, and transportation expenses. Our operating netback in 2017 was $27.47/boe. |
(3) |
FD&A costs are calculated as the sum of field capital of $330.1 million plus acquisition capital of $944.3 million plus the change in FDC for the period of $764.0 million (PDP), $1,226.3 million (TP) and $1,250.0 million (TPP), divided by the change in total reserves, other than from production, for the period. |
(4) |
Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap’s production averaged 57,450 boe/d in 2017. |
(5) |
Reserve life index (“RLI”) is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 59,707 boe/d. |