Whitecap Resources Inc. Announces Third Quarter 2017 Results, 2018 Per Share Growth and 5% Dividend Increase Within Funds Flow

CALGARY, Nov. 1, 2017 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to report its operating and unaudited financial results for the three and nine months ended September 30, 2017.

Selected financial and operating information is outlined below and should be read with Whitecap's unaudited interim consolidated financial statements and related Management's Discussion and Analysis ("MD&A") which are available at www.sedar.com and on our website at www.wcap.ca.

FINANCIAL AND OPERATING HIGHLIGHTS

		Three months ended September 30			Nine months ended September 30
Financial ($000s except per share amounts)		2017	2016		2017	2016
Petroleum and natural gas sales		232,882	178,498		716,334	426,157
Net income (loss)		3,689	6,350		107,761	(20,356)
	Basic ($/share)	0.01	0.02		0.29	(0.06)
	Diluted ($/share)	0.01	0.02		0.29	(0.06)
Funds flow ^(1)		118,979	106,326		365,084	266,933
	Basic ($/share) ^(1)	0.32	0.29		0.99	0.81
	Diluted ($/share) ^(1)	0.32	0.29		0.98	0.80
Dividends paid or declared		25,851	25,698		77,450	90,776
	Per share	0.07	0.07		0.21	0.28
Total payout ratio (%) ^(1)		97	55		98	69
Development capital ^(1)		89,903	32,945		281,618	94,342
Property acquisitions		24,962	987		31,868	618,522
Property dispositions		-	(281)		(5,821)	(144,414)
Net debt ^(1)		842,897	821,731		842,897	821,731
Operating
Average daily production
	Crude oil (bbls/d)	44,001	36,094		43,216	30,828
	NGLs (bbls/d)	3,503	2,991		3,341	3,142
	Natural gas (Mcf/d)	62,362	60,994		60,800	61,616
	Total (boe/d)	57,898	49,251		56,690	44,239
Average realized price ^(2)
	Crude oil ($/bbl)	52.77	48.14		55.08	45.03
	NGLs ($/bbl)	28.31	17.47		27.96	15.13
	Natural gas ($/Mcf)	1.77	2.47		2.47	1.94
	Total ($/boe)	43.72	39.39		46.29	35.16
Netbacks ($/boe)
	Petroleum and natural gas sales (before tariffs) ^(1)	44.90	41.42		47.81	37.27
	Tariffs ^(1)	(1.18)	(2.03)		(1.52)	(2.11)
	Realized hedging gain (loss)	0.08	3.27		(0.78)	5.51
	Royalties	(5.89)	(5.99)		(6.71)	(4.85)
	Operating expenses	(10.61)	(9.12)		(10.51)	(9.29)
	Transportation expenses	(1.85)	(0.76)		(1.53)	(0.84)
Operating netbacks ^(1)		25.45	26.79		26.76	25.69
	General and administrative expenses	(1.30)	(1.34)		(1.31)	(1.35)
	Interest and financing expenses	(1.66)	(1.93)		(1.73)	(2.23)
	Transaction costs	-	-		-	(0.03)
	Settlement of decommissioning liabilities	(0.15)	(0.05)		(0.11)	(0.05)
Funds flow netbacks ^(1)		22.34	23.47		23.61	22.03
Share information (000s)
Common shares outstanding, end of period		369,818	367,655		369,818	367,655
Weighted average basic shares outstanding		369,840	367,623		369,333	330,121
Weighted average diluted shares outstanding		371,995	370,227		371,536	332,452

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

Whitecap was once again able to deliver another strong quarter of operating and financial results with Q3/17 production volumes averaging 57,898 boe/d which is at the higher end of our forecasted 57,000 to 58,000 boe/d and a 3% increase over Q2/17 production volumes. The execution of our third quarter development capital program continued to provide highly efficient production additions where we spent approximately $89.9 million in development capital drilling 66 wells which included 47 Viking horizontal wells in western Saskatchewan, 10 wells in southwest Saskatchewan, 5 wells in the Deep Basin area of Alberta and 4 Cardium wells in the Ferrier and Willesden Green areas of Alberta.

We highlight the following accomplishments in the third quarter:

• Average production for the quarter increased by 18% (17% per share) to 57,898 boe/d (82% oil and NGLs) compared to 49,251 boe/d (79% oil and NGLs) in Q3/16.
  
  
• Funds flow for the quarter totalled $119.0 million ($0.32 per share) compared to $106.3 million ($0.29 per share) in Q3/16, an increase of 12% (10% per share).
  
  
• Achieved a total payout ratio of 97% in Q3/17, including development capital spending of $89.9 million and dividend payments of $25.9 million.
  
  
• Whitecap continued to prudently protect its funds flow and lock in economic returns on its 2018 capital budget through our active risk management program. The Company has now hedged 40% of its estimated 2018 crude oil production (net of royalties) at an average floor price of approximately C$62.00/bbl.
  
  
• Consolidated working interest, primarily in our Boundary Lake and Deep Basin areas, by spending $25 million of acquisition capital to add high quality, light oil drilling locations, production volumes and associated facilities.
  
  
• Continued to use the normal course issuer bid ("NCIB"), repurchasing 99,900 common shares at an average cost of $8.77 per share for total consideration of $0.9 million.

As part of our 2018 forward planning and as previously discussed in our press release dated August 1, 2017, we have elected to accelerate approximately $30 to $35 million of development capital from 1H/2018 into 2017 to provide a more balanced and efficient capital program as we transition from 2017 to 2018. Including the accelerated capital which we anticipate adding 300-400 boe/d to our average 2017 production, we are now forecasting a 2017 total payout ratio of 89% and $52 million of free funds flow. The development capital advanced into 2017 reduces the capital intensity and potential impacts of service sector constraints that are generally experienced in the first half of the year. This capital acceleration into 2017 includes $4 to $9 million of incremental waterflood capital to mitigate decline rates and $26 million of drilling and completion capital primarily in our Viking and Deep Basin plays.

Our Viking program continues to deliver industry leading capital efficiencies which have been driven by improving spud to rig release drilling times on our standard length horizontal and extended reach horizontal ("ERH") wells which have been averaging 2.0 days and 2.4 days, respectively. To take advantage of these program efficiencies, we elected to expand our 2017 Viking drilling program by 14 wells in Q3/17.

At Wapiti in the Deep Basin, our enhanced well placement and completion designs have continued to deliver excellent results with average IP(180) oil rates of 220 bbls/d for the most recent 6 standard length horizontal wells drilled. In addition, the initial gas to oil ratios ("GOR") of all these wells have been lower than expected which may be an indication of better reservoir contact and could result in higher ultimate oil recoveries per well. With our most recent Wapiti spud to rig release drilling time down to less than 6 days (2,800 meters total depth), we have elected to move 6 wells from our 2018 program into Q4/17 to take advantage of, and maintain, these strong capital and production efficiencies.

As part of our ongoing monitoring and optimization of our existing enhanced oil recovery ("EOR") projects, we have recently identified in our Elnora Nisku oil pool that the natural aquifer is not fully supporting the northeastern portion of the pool to the extent we had originally estimated. Therefore, we have proactively limited the production rate from the pool together with increasing and readjusting our water injection volumes to more effectively support the producing wells in the pool to ensure the optimal recovery of the oil in place. The net effect of this decision is a near-term reduction in the pool productivity by 1,800 boe/d with no associated impact to the expected reserves recovered. This has been confirmed by our independent reserve evaluators. We are actively reconfiguring our water injection and corresponding depletion strategy for this asset which will include drilling an injection well in early Q1/18 and implementing an optimal pool production plan in early 2018 which will include the drilling of an additional horizontal producing well.

The combined impact to our average annual production in 2017, as a result of proactively limiting our production at Elnora and the abnormally high level of third party facility downtime experienced in Q2/17 and Q3/17, both of which were not originally budgeted, is approximately 1,300 boe/d. We have been able to offset this production with excellent drilling and operational execution to date across our core areas and, as a result, our 2017 annual average production guidance of 57,000 boe/d remains unchanged.

DIVIDEND INCREASE

Whitecap's board of directors has approved effective for the December 2017 dividend, an increase to the Company's monthly dividend to $0.0245 per share from $0.0233 per share, an increase of 5%, thereby demonstrating confidence in our ability to generate free funds flow and our commitment to return cash to our shareholders even in a low commodity price environment. Since converting to a dividend and growth model in 2013, Whitecap has been able to differentiate its business model by delivering a compound annual growth rate on production per share of 5% and paying $670 million of cumulative dividends all within internally generated funds flow. At the same time, we have continued to maintain a strong balance sheet by methodically hedging to mitigate the volatility in our funds flow in order to securely execute our capital plans. Over the next three years, we anticipate continuing to deliver a compound annual growth rate on production per share of 3% to 5% in combination with a sustainable and growing dividend. We anticipate that on a flat commodity price assumption of US$53.00/bbl WTI, a C$/US$ exchange rate of $0.78 and $2.25/GJ AECO, we will be able to generate free funds flow (after development capital spending and dividend payments) in excess of $250 million over the next three years.

2018 BUDGET

We are excited about the outlook for Whitecap as we transition from a successful 2017 into 2018. Our board of directors has approved a base capital budget of $370 to $390 million which includes the drilling of 240 (210.4 net) wells. We maintain the operational and financial flexibility to accelerate our capital program should commodity prices strengthen from current levels. Our objective is to provide long-term sustainable returns for our shareholders, focusing on financial returns within funds flow rather than the pursuit of production growth alone. This is accomplished by balancing our capital program between quick payout, high rate of return projects and waterflood and EOR projects that typically have longer capital payouts but provide higher long-term value as well as mitigate production declines from primary production. Once again, our capital budget is anticipated to deliver 3% to 5% production per share growth along with an increased annual dividend of $0.294 per share with a total annual payout ratio of 90%. We anticipate this will result in free funds flow of approximately $54 million on a commodity price assumption of US$53.00/bbl WTI, a C$/US$ exchange rate of $0.78 and $2.25/GJ AECO. We anticipate that 81% of our capital program will be spent on drilling, completion, equipping and tie-ins, 11% on decline rate mitigation including EOR and waterflood projects, 4% on facility expansions, 3% on recompletions and workovers, and 1% on health, safety and environment projects.

West Central Alberta ($68 million) – In West Pembina, we plan on drilling 17 (13.3 net) Cardium oil wells of which 82% are ERH wells and 1 (0.9 net) water injection well. Of the wells drilled in West Pembina, 15 (11.4 net) wells are part of the redevelopment of our active waterfloods.

In our other Cardium focus areas of Ferrier and Garrington, we plan on drilling 7 (6.7 net) horizontals oil wells, including 5 (4.7 net) in Ferrier and 2 (2.0 net) in Garrington. The Ferrier wells are a continuation of our redevelopment of the legacy vertical well waterflood. We are also spending approximately $3 million in Ferrier to expand our injection and waterflood facilities to further mitigate production declines and increase reserve recoveries.

In Elnora, we anticipate drilling 2 (2.0 net) horizontal wells, one of which will be an injection well, and have also allocated $2 to $3 million to injection and associated facility enhancements for this area.

West Central Saskatchewan ($120 million) – In the Viking, we plan on drilling 125 (119.4 net) horizontal light oil wells of which 61% will be ERH wells. In addition, 11 (10.9 net) of these wells will be associated with the continued redevelopment of our existing waterfloods. We have also allocated $8 to $10 million for facility maintenance and expansion of which 50% is directly associated with waterflood projects.

Southwest Saskatchewan ($84 million) – Continuing on the success of our 2017 drilling program, we are increasing the capital allocated to this asset by approximately 75% in 2018 and anticipate drilling 63 (44.5 net) horizontal oil wells of which 46 (34.8 net) wells will be in the unconventional Atlas and upper Shaunovan formations and 17 (9.6 net) wells will be in the conventional Success and Roseray formations including 1 water injection well. We will also allocate $14 to $16 million to upgrade and expand waterflood facilities and injection to support and lower the production declines on both new and existing wells.

Boundary Lake ($24 million) – We anticipate drilling 6 (5.9 net) horizontal development wells which will be supported by $6 to $7 million in waterflood expansion and optimization capital to mitigate production declines and improve reserve recovery for the 2018 drills as well as the prior horizontal drills and the legacy vertical producers.

Deep Basin ($78 million) – As a follow-up to the significant capital efficiency improvements and production success achieved at Wapiti, we plan on drilling 12 (12.0 net) Cardium horizontal oil wells of which 58% will be ERH wells. We also anticipate drilling 7 (5.7 net) development Dunvegan wells.

2018 Budget Summary

		2017 Forecast ^(1)	2018 Budget ^(2)	% Change
Average production (boe/d)		57,000	58,800 – 60,000	4%
	Per million shares (fully diluted)	153	159	4%
	% oil and NGLs	82%	83%	1%
Funds flow netbacks ($/boe) ^(3)		$23.60	$25.00	6%
Funds flow ($MM) ^(3)		$491	$543	11%
	Per share (fully diluted) ^(3)	$1.32	$1.45	10%
Development capital ($MM) ^(3)		$330 - $335	$370 - $390	13%
Total dividends		$104	$109	5%
	Per share ^(3)	$0.280	$0.294	5%
Free funds flow ($MM) ^(3)		$52	$54	4%
Total payout ratio^(3)		89%	90%	1%
Net debt to funds flow		1.6x	1.4x	(13%)
WTI (US$/bbl)		50.08	53.00	6%
Edmonton Par Differential (US$/bbl)		(2.73)	(3.50)	28%
CAD/USD exchange rate		0.77	0.78	1%
Natural gas (AECO C$/GJ)		2.02	2.25	11%

^(1)	2017 calculations based on development capital of $335 million.
^(2)	2018 calculations based on annual production of 59,500 boe/d and development capital of $380 million.
^(3)	Refer to the Non-GAAP Measures section of this press release for additional disclosures and assumptions.

Whitecap is proud to present a balanced, repeatable and low risk 2018 capital budget, both from a cost and production perspective. We continue to utilize ever advancing technologies to enhance economic returns in each of our core areas. Our current drilling inventory of 2,895 (2,321.4 net) locations, of which 34% are ERH locations and optimization opportunities, are expected to provide us with sustainable per share growth and significant free funds flow generation in 2018 and beyond.

LONG-TERM OUTLOOK

Whitecap's success to date has been the result of our disciplined approach to capital execution with a focus on strong return on capital projects which allows us to continue our organic per share growth within our expected funds flow. The qualities of our asset base include lower production declines, high operating netbacks and significant growth opportunities with strong capital efficiencies which are the key ingredients to a growing free funds flow profile over time. This strategy has helped us to build a long-term sustainable entity able to grow on a per share basis and to pay a dividend with a total payout ratio of less than 100%. Whitecap's objective, should we have higher free funds flow than currently budgeted, is to enhance shareholder returns from our base case by increasing our per share growth organically or through property acquisitions, consistent increases to our dividends and/or using the normal course issuer bid.

We anticipate an improving macro environment which will lead to an upward trend in crude oil prices as we enter 2018. We believe the fundamentals for supply and demand in the crude oil market are becoming more balanced, supported by the visible tightening in global oil inventories, a more disciplined approach to return focused investing in the energy space and the willingness for other oil producing countries to extend production cuts beyond the current timeframes. The commodity price environment over the last three years has been a volatile and challenging one, however, we have been able to navigate effectively through this environment by focusing on operational execution, financial discipline and per share financial returns. Beyond 2018, our strategy remains equally as robust as we anticipate delivering strong corporate returns, continuing to grow production 3% to 5% per share, paying a consistent and growing dividend, all within our expected funds flow. Should commodity prices be higher than our flat crude oil price assumption of US$53.00/bbl, we have an ability to increase our production per growth beyond the targeted 3% to 5%. We also anticipate that we will be able to continue to reduce our net debt to funds flow ratio between 1.2 to 1.5 times in 2018.

Our Whitecap team has been able to deliver exceptional results to date and will proactively look for additional opportunities to enhance shareholder returns as we move through 2018 and beyond.

On behalf of our Management team and Board of Directors, we would like to thank you for your support of Whitecap and look forward to reporting continuing positive results in the future.

Note Regarding Forward-Looking Statements

This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including statements about our strategy, plans and objectives, 2017 and 2018 production, production per share, operating netbacks, funds flow netbacks, funds flow, funds flow per share, future dividends, free funds flow, total payout ratio, net debt to funds flow ratio, our 2017 and 2018 capital program and allocation thereof, our capital efficiencies; the Company's ability to accelerate development capital spending and the benefits derived therefrom; development and completion plans and payout; water flood and enhanced oil recovery plans and anticipated results therefrom; initial gas to oil ratios; anticipated future per share growth; the benefits to be obtained from our hedging program; effect of the capital program on future production decline rates; the timing, location and extent of future drilling operations including the quantity of drilling locations in inventory; the 2018 drilling program including the quantity of wells to be drilled; well payout and economic rates of return; expansion of injection and waterflood facilities in west central Alberta, west central Saskatchewan and southwest Saskatchewan and the costs associated therewith; expected results from waterflood activities on reserve recovery; long-term benefits of current drilling inventory; the sources of funding dividends and our capital program; anticipated compounded annual growth rates on production; anticipated free funds flow over the next three years; anticipated shareholder returns; the anticipated benefits from the NCIB; the results of our operations; plans to allocate future funds flow; ability to increase long-term total shareholder return; enhance our per share metrics; anticipated net debt to funds flow ratio; anticipated macro environment; our future dividends and dividend policy; industry conditions, future exchange rates and commodity prices.

The forward-looking information is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve and resource volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labour and services; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions, ability to market oil and natural gas successfully and our ability to access capital.

Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Whitecap can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Whitecap's prospective results of operations, funds flow netbacks, funds flow, free funds flow, total payout ratio, net debt to funds flow, and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was made as of the date of this document and was provided for the purpose of providing further information about Whitecap's future business operations. Whitecap disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein.

These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Drilling Locations

This press release discloses drilling inventory in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from McDaniel & Associates Consultants Ltd.'s reserves evaluation effective December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 2,895 total drilling locations identified herein, 1,183 are proved locations, 124 are probable locations and 1,588 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

Production Rates

Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Whitecap.

"Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Non-GAAP Measures
This press release includes non-GAAP measures as further described herein. These non-GAAP measures do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and therefore may not be comparable with the calculation of similar measures by other companies.

"Cash dividends declared per share" represents cash dividends declared or paid per share by Whitecap.

"Development capital" represents expenditures on property, plant and equipment ("PP&E") excluding corporate and other assets.

The following table reconciles expenditures on PP&E (a GAAP measure) to development capital (a non-GAAP measure):

	Three months ended		Nine months ended
	September 30		September 30
($000s)	2017	2016	2017	2016
Expenditures on PP&E	90,033	33,134	282,063	94,655
Expenditures on corporate and other assets	(130)	(189)	(445)	(313)
Development capital	89,903	32,945	281,618	94,342

"Funds flow" represents cash flow from operating activities adjusted for changes in non-cash working capital.

"Funds flow per share" represents funds flow divided by the basic or diluted weighted average shares outstanding in the period. Management considers funds flow and funds flow per share to be key measures as they demonstrate Whitecap's ability to generate the cash necessary to pay dividends, repay debt, make capital investments and/or to repurchase common shares under the Company's NCIB. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow provides a useful measure of Whitecap's ability to generate cash that is not subject to short-term movements in non-cash operating working capital.

The following table reconciles cash flow from operating activities (a GAAP measure) to funds flow and free funds flow (non-GAAP measures):

	Three months ended		Nine months ended
	September 30		September 30
($000s)	2017	2016	2017	2016
Cash flow from operating activities	100,263	89,471	361,887	266,335
Changes in non-cash working capital	18,716	16,855	3,197	598
Funds flow	118,979	106,326	365,084	266,933
Cash dividends declared	25,851	25,698	77,450	90,776
Development capital	89,903	32,945	281,618	94,342
Free funds flow	3,225	47,683	6,016	81,815
Total payout ratio (%)	97	55	98	69

"Free funds flow" represents funds flow less cash dividends declared and development capital.

"Funds flow netbacks" are determined by deducting cash general and administrative expenses, interest and financing expenses, transaction costs and settlement of decommissioning liabilities from operating netbacks.

The operating and cash netbacks ($/boe) assumptions used for the 2017 forecast and 2018 budget as follows:

	2017 Forecast	2018 Budget
Petroleum and natural gas sales, before tariffs	48.04	50.20
Tariffs	(1.49)	(1.09)
Realized hedging gain (loss)	(0.87)	(1.73)
Royalties	(6.65)	(6.27)
Operating expenses	(10.64)	(11.00)
Transportation expenses	(1.63)	(2.00)
Operating netbacks	26.76	28.11
General and administrative expenses	(1.31)	(1.30)
Interest and financing expenses	(1.72)	(1.61)
Settlement of decommissioning liabilities	(0.13)	(0.20)
Funds flow netbacks	23.60	25.00

"Operating netbacks" are determined by deducting realized hedging losses or adding realized hedging gains and deducting royalties, operating expenses and transportation expenses from petroleum and natural gas sales. Operating netbacks are per boe measures used in operational and capital allocation decisions.

"Net debt" is calculated as long-term debt plus working capital surplus or deficit adjusted for risk management contracts. Net debt is used by management to analyze the financial position and leverage of Whitecap.

The following table reconciles long-term debt (a GAAP measure) to net debt (a non-GAAP measure):

($000s)	September 30                         2017	December 31                           2016
Long-term debt	802,408	773,395
Current liabilities	194,190	231,416
Current assets	(126,856)	(111,194)
Risk management contracts	(26,845)	(75,037)
Net debt	842,897	818,580

"Petroleum and natural gas sales, before tariffs" are determined by adding back tariffs netted against petroleum and natural gas sales. Management believes that petroleum and natural gas sales, before tariffs provides a useful measure of Whitecap's realized commodity prices before the impact of transporting products to market. 

The following table reconciles petroleum and natural gas sales (a GAAP measure) to petroleum and natural gas sales, before tariffs (a non-GAAP measure):

	Three months ended September 30		Nine months ended September 30
($000s)	2017	2016	2017	2016
Petroleum and natural gas sales	232,882	178,498	716,334	426,157
Tariffs	6,288	9,199	23,530	25,638
Petroleum and natural gas sales, before tariffs	239,170	187,697	739,864	451,795

"Tariffs" represent pipeline tariffs incurred by commodity purchasers and marketing companies subsequent to the delivery of the Company's product, which have been charged back to Whitecap. Under IFRS, tariffs are reflected on a net basis (tariffs are netted against petroleum and natural gas sales). Tariffs will fluctuate quarterly based on pipeline connectivity or downtime, weather, shipper status and pipeline shipping arrangements. As the amount of tariffs recognized decreases, there is an offsetting increase in transportation expense.  Management believes that presenting tariffs separately provides a useful measure of the total costs of transporting a product to market as, on a combined basis, tariffs plus transportation expenses are generally consistent with prior periods.

"Total payout ratio" is calculated as cash dividends declared plus development capital, divided by funds flow.

SOURCE Whitecap Resources Inc.

Grant Fagerheim, President & CEO or Thanh Kang, CFO, Whitecap Resources Inc., 3800, 525 - 8th Avenue SW, Calgary, AB T2P 1G1, Phone [phone], www.wcap.ca

Related Links

www.wcap.ca