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SOURCE Whitecap Resources Inc.
CALGARY, Oct. 15, 2013 /CNW/ - Whitecap Resources Inc. ("Whitecap" or the "Company") (TSX: WCP) is pleased to announce a 15 percent increase to our credit facilities from $520 million to $600 million in addition to providing shareholders with an update on our successful capital execution thus far in 2013. Our third quarter operational results have once again exceeded expectations with average production over 1,000 boe/d above our 20,000 boe/d production forecast providing us with the opportunity to increase our average 2013 production guidance of 19,200 boe/d to 19,500 boe/d.
Based on our mid-year interim reserves review, our lenders have agreed to increase our credit facility 15 percent to $600 million from the previous $520 million. In addition, as part of our $600 million credit facility, our lenders have agreed to term out $200 million of our core debt for five years at an effective interest rate of 5.325 percent maturing on October 2, 2018. The increase to our credit capacity and our ability to secure $200 million of term debt financing at an attractive long term interest rate provides more predictability to our free cash flow, strengthens our financial flexibility and increases the overall sustainability of our dividend-growth model.
Recent operational results in each of our core areas continue to be very strong and we anticipate a positive independent 2013 year-end reserves evaluation. The 2013 year-end borrowing base review is scheduled for May 31, 2014.
Whitecap was very active in the field drilling a total of 35 (27.0 net) wells in the third quarter of 2013 while spending approximately $65.5 million in development capital. Year to date we have drilled a total of 90 (68.1 net) wells with a 100 percent success rate. The success we have achieved optimizing our field operations, in combination with our development drilling program, continues to provide our shareholders with sustainable dividends and per share growth all funded by internally generated cash flow.
West Central Saskatchewan - Viking Light Oil
In the third quarter of 2013 we drilled 21 (15.7 net) Viking horizontal oil wells including 3 (2.4 net) wells drilled late in the third quarter on our recently acquired Eagle Lake property which closed in May 2013 bringing our total for the year to 43 (34.5 net) wells. In our Lucky Hills area our costs to drill, complete and equip ("DC&E") averaged $810,000 per well, a 7 percent reduction compared to our type curve costs of $875,000 per well along with our cycle times (spud to on production) improving to 11 days per well. The average IP(30) oil rates in the third quarter were 121 bopd compared to 90 bopd in the first quarter 2013 and 68 bopd in 2012. Our recent Viking wells have payout periods of less than 10 months per well.
Since our initial entrance into the Viking light oil play in February 2012 we have been able to reduce operating costs in our Lucky Hills area by over 15 percent to the current $8.50/boe. The decrease is a direct result of our operational diligence in consolidating and optimizing our production infrastructure and continued focus on maximizing the cash flow netback on our assets as we grow the production.
West Central Alberta - Garrington (Cardium Light Oil)
In the third quarter of 2013 we drilled 5.0 (3.3 net) Cardium horizontal oil wells including 2 (2.0 net) extended reach horizontal ("ERH") wells bringing our total for the year to 24 (13.3 net) wells. The results from our three standard length horizontal wells have been consistent with our expectations.
The horizontal producing sections of our two ERH wells are 1.5 times longer than our standard horizontals wells with average IP(30) rates that are 2.3 times higher than our standard length horizontal wells at 781 boe/d. The exceptional economics result in payout of capital per well occurring within 120 to 160 days. As a result of this step change to our economics we have increased our 2013 capital budget to include one additional ERH well that has now been drilled and placed on production. For each ERH well we are forecasting 1.5 times increase in productivity with DC&E costs of $3.5 million per well.
West Central Alberta - Greater Pembina (Cardium Light Oil)
In our greater Pembina area we drilled 6 (5.5 net) Cardium horizontal oil wells of which five were in east Pembina bringing our total for the year to 15 (14.0 net) wells. Current average DC&E costs in east Pembina have averaged $2.3 million per well, 10 percent lower than our current type well economics.
Five wells drilled in east Pembina were on lands acquired in the third quarter of 2013 for $14.0 million which included 25 (24.0 net) Whitecap-identified horizontal Cardium development drilling locations. The IP(30) rates from the five wells drilled on the acquired lands were 32 percent higher than the previous 12 wells in the immediate area (286 boe/d compared to 217 boe/d).
In addition to our drill bit success in east Pembina we constructed and brought on line a 100 percent working interest battery and gas handling facility in our Ferrier area, eliminating the need to utilize third party facilities.
Peace River Arch
Deep Basin - Dunvegan Light Oil
Since 2012 we have been acquiring land and drilling opportunities in the emerging Dunvegan light oil horizontal development play and to date have spent approximately $38.0 million including $15.1 million in the third quarter of 2013 through a series of asset acquisitions. We drilled our first well in December 2012 and have now drilled a total of 5 (4.4 net) Dunvegan horizontal oil wells including 4 (3.4 net) wells in 2013. The wells drilled in the Deep Basin have met or exceeded our type curve expectations with average DC&E costs per well of $3.5 million with shallower decline profiles and higher stabilized rates relative to the Cardium and Viking wells.
We currently have an inventory of 83 (79.5 net) Dunvegan light oil development locations which complement our high growth Viking and Cardium resource inventory for long term growth and sustainability.
Valhalla - Montney Light Oil
No wells were drilled in the third quarter as we focused on Phase 2 of our waterflood expansion on the northwest portion of the pool with water injection commencing in early October 2013. This expansion includes an additional 800 acres in the northwest portion of the pool under waterflood that has had no previous water injection and very little production. We will continue to monitor incremental waterflood response as we move through the balance of 2013 and into 2014.
2013 UPWARD GUIDANCE
Oil prices continue to remain robust averaging WTI C$109.66 in the third quarter of 2013 which has provided us with the ability to lock in commodity prices at attractive levels, providing significant return on investment for our shareholders. Currently for the fourth quarter of 2013 we have 87 percent of our forecasted oil production hedged at an average WTI price of C$97.54 per barrel, in 2014 we have 77 percent of our forecasted oil production hedged at an average WTI price of C$94.56 per barrel, and in 2015 we have 15 percent of our forecasted oil production hedged at an average WTI price of C$90.52 per barrel. The stability in our revenues provides us with greater predictability over our cash flow for dividend payments and capital reinvestment. In addition, operational results to date have been at or better than expectations which allows us to increase our annual production guidance from 19,200 boe/d to 19,500 boe/d. We have also increased our capital budget for 2013 from $180 million to $188 million which includes the drilling of one additional ERH Cardium horizontal well at Garrington and three additional Viking horizontal wells at Lucky Hills.
Whitecap continues to strengthen what we believe to be the four pillars for success in our dividend-growth model being: (1) decline rate, (2) capital efficiency, (3) cash flow netback and (4) inventory of top tier locations for continued long term growth. Our average base production decline has been reduced from 32 percent in 2012 to 27 percent in 2013 and we expect that decline to be 24 to 25 percent in 2014. Since 2012 our capital efficiency has improved significantly as our technical teams have been successful in reducing capital costs and at the same time increasing well productivity in each of our core areas as noted in our operations update above. In 2012 our cash flow netback was $37.69/boe compared to our anticipated cash flow netback of $40.00/boe in 2013, a six percent increase. Our target cash flow netback longer term is between $38/boe to $41/boe. In 2012 we had a development well inventory of 836 locations and have since advanced our inventory 60 percent to currently 1,333 locations, over 73 percent of which we believe will achieve or exceed our current type well projections.
On November 7, 2013 we look forward to reporting our third quarter results and operational and financial guidance for the upcoming 2014 year.
Whitecap Resources Inc. is a dividend paying, oil-weighted company focused on providing sustainable monthly dividends to its shareholders and per share growth through a combination of accretive oil-based acquisitions and organic growth on existing and acquired assets. For further information about Whitecap please visit our website at www.wcap.ca.
Note Regarding Forward-Looking Statements and Other Advisories
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", "project", "expect", "goal", "plan", "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. In particular, this press release contains forward-looking information relating to our 2013 production guidance, predictability of free cash flow, financial flexibility, overall sustainability of our dividend-growth model, positive independent 2013 year-end reserves evaluation, ability to continue to provide shareholders with sustainable dividends and per share growth all funded by internally generated cash flow, ERH well economics, 2013 capital budget, base decline rate, anticipated cash flow netback, risk management program, drilling inventory or development and drilling plans, and potential growth.
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 securityholders 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).
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.
This press 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.
"Funds from operations" represents cash flow from operating activities adjusted for changes in non-cash working capital, transaction costs and asset retirement settlements. Management considers funds from operations to be a key measure as it demonstrates Whitecap's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds from operations 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.
"Operating netbacks" are determined by deducting royalties, production expenses and transportation and selling expenses from oil and gas revenue. Operating netbacks are per boe measures used in operational and capital allocation decisions.
"Cash flow netbacks" are determined by deducting cash general and administrative and interest expense from operating netbacks.
"Free cash flow" is determined by deducting dividends declared and development capital expenditures from funds from operations.
"Boe" means barrel of oil equivalent on the basis of 6 mcf of natural
gas to 1 bbl of oil. Boes 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.
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