Athabasca Oil Corporation Reports Second Quarter 2014 Financial and Operating Results

 Athabasca Oil Corporation Reports Second Quarter 2014 Financial and Operating  Results  CALGARY, Aug. 6, 2014 /CNW/ - Athabasca Oil Corporation (TSX: ATH)  ("Athabasca" or "the Company") is pleased to report its second quarter 2014  financial and operating results.  Second quarter highlights:            --  produced an average of 5,767 barrels of oil equivalent per day             ("boe/d") with 52% liquids, in line with guidance of 5,500 to             6,000 boe/d;         --  obtained extended production results from two additional             Duvernay wells at Kaybob West; 8-29-64-20W5 had an established             30-day restricted rate of 784 boe/d with a free condensate             yield of 763 barrels per million cubic feet ("bbls/mmcf") and             the second well at 4-29-64-20W5 had an established 30-day             restricted rate of 615 boe/d with a free condensate yield of             710 bbls/mmcf. Both wells support the Company's interpretation             of the prospectivity of the volatile oil window where Athabasca             has substantial acreage;         --  reached 89% completion on Hangingstone Project 1, Athabasca's             12,000 barrels per day ("bbls/d") steam assisted gravity             drainage ("SAGD") project; and         --  entered into new credit facilities providing for approximately             $425 million of committed funding for three to five year terms.  The Company confirms that it continues to work with Phoenix Energy Holdings  Limited ("Phoenix") to close the Dover put transaction in accordance with the  terms of the Put/Call Option Agreement. The parties have a mutually understood  path to closing the transaction, including targeted timelines.  "Athabasca is working diligently to advance the closing of the Dover put  transaction and we appreciate the ongoing patience of our shareholders," says  Sveinung Svarte, President and CEO. "Operationally, we remain very encouraged  by the results of our Duvernay wells and are pleased with the advancement of  Hangingstone Project 1, which is progressing as planned. We continue to be  committed to strong capital discipline and look forward to releasing an  updated corporate strategy and capital plans following the closing of the  Dover transaction."  Athabasca has filed its financial statements and management's discussion and  analysis ("MD&A") for the three and six months ended June 30, 2014. These  documents are available on the Company's website and later this  morning from SEDAR An updated investor presentation has also  been posted on the Company's website. Selected financial and operating  information is outlined below and should be read in conjunction with  Athabasca's audited financial statements and MD&A.                                                                                                        Three months ended     Six months ended                                        June 30,              June 30,     ($ Thousands, except per          2014       2013       2014       2013     share and boe amounts)     LIGHT OIL NETBACK(1)                                                            Petroleum and natural   $   34,626 $   35,717 $   69,272 $   63,722         gas sales         Midstream revenues             755        257      1,558        360         Royalties                  (2,794)    (2,812)    (7,822)    (4,229)         Operating expenses and     (8,380)    (8,768)   (17,859)   (17,370)         transportation                                 $   24,207 $   24,394 $   45,149 $   42,483     CASH FLOWS                                                                      Funds Flow from         $    4,882 $    1,368 $    8,714 $  (6,918)         Operations(1)         Funds Flow from         $     0.01 $     0.00 $     0.02 $   (0.02)         Operations per share         (basic and diluted)     NET LOSS AND COMPREHENSIVE                                                  LOSS         Net loss and            $ (56,766) $ (29,986) $ (78,119) $ (55,476)         comprehensive loss         Net loss and            $   (0.14) $   (0.07) $   (0.19) $   (0.14)         comprehensive loss per         share (basic & diluted)     SALES VOLUMES                                                                   Oil (bbls/d)                 2,184      2,695      2,297      2,742         Natural gas (mcf/d)         16,563     21,942     18,282     19,080         Natural gas liquids            823        906        688        729         (bbls/d)       Total (boe/d)                  5,767      7,258      6,032      6,651       Oil and Natural gas              52%        50%        49%        52%       liquids %     REALIZED PRICES                                                                 Oil ($/bbl)             $   104.04 $    88.22 $    96.50 $    84.72         Natural gas ($/mcf)           5.01       4.08       5.67       3.74         Natural gas liquids          85.46      71.92      83.37      67.07         ($/bbl)       Realized price ($/boe)         65.97      54.08      63.45      52.98         Royalties ($/boe)           (5.32)     (4.26)     (7.16)     (3.52)         Operating expenses and                                             transportation(2)         ($/boe)                    (14.53)    (12.89)    (14.93)    (14.19)       Light Oil Netback(1)       ($/boe)                   $    46.12 $    36.93 $    41.36 $    35.28     CAPITAL EXPENDITURES                                                            Light Oil Division      $   14,847 $   47,461 $   92,296 $  223,420         Thermal Oil Division        90,556     87,401    248,514    166,633         Assets held for sale         2,600      4,800      6,600      9,383         Corporate                    1,053      3,048      2,508      7,655                                 $  109,056 $  142,710 $  349,918 $  407,091  _________________________________________________     (1)  Refer to "Advisories and Other Guidance" on page 18 of the MD&A          for additional information on Non-GAAP Financial Measures.     (2)  For the six months ended June 30, 2014, operating expenses and          transportation expenses in the Netback figure includes midstream          revenues          of $1.43/boe (2013 - $0.25/boe) and for the three months ended          June 30, 2014, $1.44/boe (2013 - $0.39/boe).                                                                                                              June 30, December 31,     As at ($ Thousands)                             2014         2013     LIQUIDITY                                                               Cash and cash equivalents              $   182,499 $    298,995       Short-term investments                           -       23,795       Add: Undrawn credit facilities             125,000      350,000       Add: Term Loan - delayed draw (US$50.0      53,380            -       million)     Available liquidity(1)                       360,879      672,790     BALANCE SHEET                                                           Total assets                             4,459,943    4,342,325       Long-term debt                             764,788      533,210       Shareholders' equity                   $ 3,301,011 $  3,373,957     (1)  Refer to "Advisories and Other Guidance" on page 18 of the MD&A          for additional information on Non-GAAP Financial Measures.  Operations Update  Light Oil  Athabasca's light oil production averaged 5,767 boe/d with 52% liquids in the  second quarter of 2014. Production was in line with prior guidance of 5,500 to  6,000 boe/d which incorporated a planned third-party downtime of 10 days. The  Company was able to achieve guidance despite an additional seven days of  unplanned third-party downtime. The combined third-party plant outages of 17  days impacted production by approximately 1,000 boe/d for the quarter.  Production volumes were supported by the winter Duvernay program which  included four horizontal wells that are now on stream with extended production  periods exceeding 30 days. The Company recognized a light oil netback of  $46.12/boe in the second quarter of 2014. Light Oil capital expenditures were  $15 million in the second quarter of 2014 primarily consisting of facility and  base maintenance projects and commissioning of the new Duvernay wells.  Duvernay Update In the Kaybob West area, the final two Duvernay wells that were completed in  the first quarter were brought on production in the second half of June  following a planned extended shut in (soak period) subsequent to the wells'  completion and initial flow back. The 8-29-64-20W5 well was soaked for 77 days  and averaged a restricted rate of 784 boe/d (644 bbls/d of condensate, 844  mcf/d of gas) in the first 30 days with a free condensate yield of 763  bbls/mmcf. The second Duvernay well at 4-29-64-20W5 was soaked for 69 days and  when brought on production, averaged a restricted rate of 615 boe/d (498  bbls/d of condensate, 702 mcf/d of gas) in the first 30 days with a free  condensate yield of 710 bbls/mmcf. Both wells continued to flow at restricted  rates at the end of the 30-day period.  The Duvernay well located at 1-7-64-20W5 in Kaybob West continues to perform  well at a restricted rate. Average production for this well was 625 boe/d (442  bbls/d of condensate, 1.1 mmcf/d of gas) in the first 90 days with a free  condensate yield of 418 bbls/mmcf. This compares to the restricted IP30 of 750  boe/d (550 bbls/d and 1.2 mmcf/d) released in May 2014.  At Simonette, Athabasca's 1-25-62-25W5 well continues to be a top producer in  the Duvernay fairway. Production through permanent facilities commenced in May  and in the first 60 days the well has produced an average restricted rate of  1,286 boe/d (820 bbls/d of condensate, 2.8 mmcf/d of gas) with a free  condensate yield of 294 bbls/mmcf. This compares to the restricted IP30 of  1,461 boe/d (945 bbls/d and 3.0 mmcf/d).  The Company believes production practices have a considerable influence on the  initial productivity and ultimate recovery of Duvernay wells. Athabasca's  practices include a post-completion soak period resulting in higher initial  flowing pressures and reduced flow back water production. By restricting rates  the Company also observes sustained production at lower pressure decline rates.  The focus of the Duvernay program to date has been to retain land, prove the  resource extent and understand the basin. In total, Athabasca has now drilled  eight horizontal Duvernay wells in the fairway, of which seven were on  production by the end of the second quarter of 2014. The Company holds 200,000  net acres of high-graded Duvernay land which contain greater than 20 meters of  shale pay and lie in the heart of the Kaybob Duvernay fairway. Approximately  two-thirds of the Duvernay acreage is extended into the intermediate term and  an additional five wells are required over the next drilling season to extend  approximately 95% of the acreage into the intermediate term. The upcoming  Duvernay program will shift to prioritizing production and cash flow growth  from the Saxon, Simonette and Kaybob West areas where Athabasca and industry  have demonstrated commercial well performance.  Athabasca anticipates a significant reduction in well costs as the play moves  towards the development stage. Cost learnings are well documented across North  American shale plays. The Company's Duvernay costs have ranged between $15 to  $19 million per well to drill and complete single well pads. This includes  vertical strat, core work and in some cases micro seismic monitoring.  Athabasca is confident in its ability to reduce costs, particularly with pad  drilling, and expects horizontal well costs to be $10 to 15 million in future  development phases of its drilling program.  Infrastructure Update In regard to Light Oil infrastructure, Athabasca completed the installation of  a pipeline connecting Athabasca's Kaybob West facility to SemCAMS' KA gas  plant. The installation was completed on behalf of a third-party, with  Athabasca retaining a 10% working interest in the 10-inch line with no capital  outlay. The Company views its regional infrastructure as a competitive  advantage providing egress to two large midstream plants and facilitating  growth into the mid-term. Ownership in infrastructure remains a strategic  advantage for Athabasca in controlling pace of development.  Thermal Oil  In the second quarter of 2014, Thermal Oil capital expenditures totaled $91  million including $88 million on Hangingstone and $3 million on Thermal Oil  exploration areas. This excludes $3 million of capital expenditures associated  with the Company's 40% interest in the Dover oil sands project.  During the second quarter of 2014, Athabasca advanced its development of  Hangingstone Project 1. The drilling and completions program is 100% complete  and has delivered better than expected cost and schedule performance. The  reservoir quality is consistent with expectations derived from Athabasca's  extensive appraisal drilling and reservoir modeling.  At the end of June 30, 2014, Hangingstone Project 1 was approximately 89%  complete with costs closely aligned with the sanctioned budget of $565  million. The focus for construction is on the completion of the central plant.  Commissioning and operations readiness plans are progressing as planned. The  teams will be ready to transition from construction near the end of the year  to achieve first steam which remains targeted towards the end of the first  quarter of 2015.  Corporate  Dover Oil Sands Project Athabasca is working diligently to close the sale of its 40% interest in the  Dover oil sands project to Phoenix. Athabasca exercised its put option under  the Put/Call Option Agreement on April 17, 2014, requiring Phoenix to purchase  the Company's Dover interests in accordance with the terms of the Put/Call  Option Agreement. The parties are jointly working toward the closing of the  transaction and have a mutually understood path to closing the transaction,  including targeted timelines. As previously disclosed, the current net  purchase price payable by Phoenix is $1,234 million.  The Company has also made a separate provision for $49 million in respect of a  potential settlement of certain claims made by Phoenix for indemnification  under the PetroChina Transaction Agreements and the AOSC MacKay Share Purchase  Agreement in relation to future thermal abandonment costs associated with  petroleum and natural gas wells located in the Dover and MacKay River areas.  The Company's payment under this settlement is contingent upon the successful  closing of the Dover Put Option.  Liquidity On May 7, 2014 Athabasca entered into new credit facilities, including term  loans and a revolving credit facility, which combined provide for  approximately $425 million of committed funding for three to five year terms.  The new credit facilities replaced the Company's previous $350 million  revolving credit facility which had a maturity date of December 31, 2014,  providing Athabasca with longer term sources of committed funding which better  match the development profile of its assets as well as more flexible covenants.  At June 30, 2014, Athabasca had liquidity of approximately $361 million,  including cash and cash equivalents, short-term investments, its undrawn $125  million revolving credit facility and a $50 million (U.S) delayed draw term  loan.  Outlook  The 2014 capital budget remains at $527 million, excluding capitalized  interest and capitalized general and administrative expenses. Second half 2014  production guidance is between 6,000 - 6,500 boe/d. The Company will release  full capital plans, details on its strategy and a preliminary 2015 outlook  following receipt of the Dover proceeds.  Athabasca views joint ventures as a mechanism to help reduce risk, accelerate  development and leverage partner expertise. As the Company advances the  development and operations of its Light Oil and Thermal Oil assets, its strong  results, scalable position and understanding of the play will continue to  attract interest from potential long-term partners.                                                                                                                                   Full Year Q3/Q4     2014 Capital Budget(1) ($ Millions)                        2014  2014     THERMAL OIL DIVISION                                                        Hangingstone Project                                $     227 $  81       Hangingstone regional infrastructure and production        58    15       support       Hangingstone Expansion                                     48    28       Other                                                      15    10                                                                 348   134     LIGHT OIL DIVISION                                                          Duvernay                                                  108    40       Montney                                                    16     5       Other                                                      21    13                                                                 145    58     CORPORATE                                                    14    12     DOVER JOINT VENTURE                                          20    13     TOTAL CAPITAL SPENDING                                $     527 $ 217     (1)  The capital budget figures above exclude capitalized interest,          financing costs, and general & administrative costs ("G&A").          Athabasca anticipates that capitalized G&A for 2014 will be          approximately $50 million.                                                                                        Six months                                          ended        Guidance     2014 Light Oil Operations         June 30,           Q3/Q4                                           2014            2014     Light oil production (boe/d)         6,032   6,000 - 6,500     Oil and natural gas liquids (%)         49              56  Conference Call, August 6, 2014 7:30 am Mountain Time (9:30 am Eastern Time)  A conference call to discuss the first quarter will be held for the investment  community and media on August 6, 2014 at 7:30 a.m. MT (9:30 a.m. ET). To  participate, please dial 888-231-8191 (toll-free in North America) or  647-427-7450 approximately 15 minutes prior to the conference call. An  archived recording of the call will be available from approximately 12:30 p.m.  ET on August 6 until midnight on August 13, 2014 by dialing 855-859-2056  (toll-free in North America) or 416-849-0833 and entering conference password  62777713.  An audio webcast of the conference call will also be available on Athabasca's  website, or the following link below:  About Athabasca Oil Corporation  Athabasca Oil Corporation is a Canadian energy company with a diverse  portfolio of thermal and light oil assets. Situated in Alberta's Western  Canadian Sedimentary Basin, the Company has amassed a significant land base of  extensive, high quality resources. Athabasca's common shares trade on the TSX  under the symbol "ATH". For more information, visit  Reader Advisory:  This News Release contains forward-looking information that involves various  risks, uncertainties and other factors. All information other than statements  of historical fact is forward-looking information. The use of any of the words  "anticipate," "plan," "continue", "estimate", "expect", "may", "will",  "project", "should", "believe", "predict", "pursue" and "potential" and  similar expressions are intended to identify forward-looking information. The  forward-looking information is not historical fact, but rather is based on the  Company's current plans, objectives, goals, strategies, estimates, assumptions  and projections about the Company's industry, business and future financial  results. This information involves known and unknown risks, uncertainties and  other factors that may cause actual results or events to differ materially  from those anticipated in such forward-looking information. No assurance can  be given that these expectations will prove to be correct and such  forward-looking information included in this News Release should not be unduly  relied upon. This information speaks only as of the date of this News Release.  In particular, this News Release may contain forward-looking information  pertaining to the following: the receipt of sale proceeds from the sale of the  Dover Investment as a result of the Company's exercise of the Dover Put  Option; the settlement of claims made by Phoenix Energy Holdings Limited  ("Phoenix") for indemnification under the agreements relating to the Company's  joint venture with Phoenix ("PetroChina Transaction Agreements"); the expected  timing of the completion of the construction of Hangingstone Project 1 and of  first steam into Hangingstone Project 1; the expected timing of the first  significant production from the Thermal Oil Division, which is expected to  come from Hangingstone Project 1; the anticipated regulatory review/approval  process in respect of the Hangingstone Expansion; the timing of the  construction of the facilities and infrastructure related to the Hangingstone  Projects, including the completion of the Hangingstone Project 1 central plant  and the Enbridge and IPF pipelines; estimated production and production goals  in respect of the Company's projects, including the anticipated production  from the Company's Light Oil division; the estimated quantity of the Company's  Proved and Probable Reserves and Contingent Resources; the potential for  future joint venture opportunities, the Company's drilling and development  plans, including in particular with respect to the Montney and Duvernay  formations; the Company's capital expenditure programs and expected future  capital expenditures; the Company's other plans for, and results of,  exploration and development activities with respect to the Thermal Oil and  Light Oil assets and the expected benefits to be received by Athabasca from  such assets; and allocations of capital.  With respect to forward-looking information contained in this News Release,  assumptions have been made regarding, among other things: the receipt of the  sale proceeds from the Company's sale of of its interest in the Dover oil  sands project in a timely manner; the Company's ability to obtain qualified  staff and equipment in a timely and cost-efficient manner; the regulatory  framework governing royalties, taxes and environmental matters in the  jurisdictions in which the Company conducts and will conduct its business; the  applicability of technologies for the recovery and production of the Company's  reserves and resources; future capital expenditures to be made by the Company;  future sources of funding for the Company's capital programs; the Company's  future debt levels; the Company's ability to obtain financing and/or enter  into joint venture arrangements, on acceptable terms; geological and  engineering estimates in respect of the Company's reserves and resources; the  geography of the areas in which the Company is conducting exploration and  development activities; and the impact that the PetroChina Transaction  Agreements will have on the Company, including on the Company's financial  condition and results of operations.  Actual results could differ materially from those anticipated in this  forward-looking information as a result of the risk factors set forth in the  Company's most recent Annual Information Form ("AIF") dated March 18, 2014,  available on SEDAR at, including, but not limited to: the  substantial capital requirements of Athabasca's projects and the ability to  obtain financing for Athabasca's capital requirements; the potential for  adverse consequences in the event that Athabasca defaults under certain of the  PetroChina Transaction Agreements; failure by counterparties (including,  without limitation, PetroChina International and Phoenix) to make payments or  perform their obligations to the Company in compliance with the terms of  contractual arrangements between the Company and such counterparties,  including in compliance with the expressed or implied time schedules set out  in such contractual arrangements, and the possible consequences thereof;  aboriginal claims; fluctuations in market prices for crude oil, natural gas  and bitumen blend;  general economic, market and business conditions in  Canada, the United States and globally; failure to obtain regulatory approvals  or maintain compliance with regulatory requirements; dependence on Phoenix as  the joint venture participant in the Dover oil sands project; failure to meet  development schedules and potential cost overruns; variations in foreign  exchange and interest rates; factors affecting potential profitability; risks  related to future acquisition and joint venture activities; reliance on,  competition for, loss of, and failure to attract key personnel; global  financial uncertainty; uncertainties inherent in estimating quantities of  reserves and resources;  changes to status given the current stages of  development; uncertainties inherent in SAGD, TAGD and other bitumen recovery  processes; expiration of leases and permits; risks inherent in Athabasca's  operations, including those related to exploration, development and production  of petroleum, natural gas and oil sands reserves and resources, including the  production of oil sands reserves and resources using SAGD, TAGD or other  in-situ technologies; risks related to gathering and processing facilities and  pipeline systems; availability of drilling and related equipment and  limitations on access to Athabasca's assets; increases in operating costs  could make Athabasca's projects uneconomic; the effect of diluent and natural  gas supply constraints and increases in the costs thereof; gas over bitumen  issues affecting operational results; environmental risks and hazards and the  cost of compliance with environmental regulations, including greenhouse gas  regulations and potential Canadian and U.S. climate change legislation; extent  of, and cost of compliance with, government laws and regulations and the  effect of changes in such laws and regulations from time to time; risks  related to Athabasca's filings with taxation authorities, including the risk  of tax related reviews and reassessments; changes to royalty regimes;  political risks; failure to accurately estimate abandonment and reclamation  costs; exploration, development and production risks inherent in crude oil and  natural gas operations, including the production of crude oil and natural gas  using multi-stage hydraulic fracture and other stimulation technologies; the  potential for management estimates and assumptions to be inaccurate; long term  reliance on third parties; reliance on third party infrastructure for project  facilities; seasonality; hedging risks; risks associated with establishing and  maintaining systems of internal controls; insurance risks; claims made in  respect of Athabasca's operations, properties or assets; the effect of a  change of control under the PetroChina Transaction Agreements; competition  for, among other things, capital, the acquisition of reserves and resources,  export pipeline capacity and skilled personnel; the failure of Athabasca or  the holder of certain licenses, leases or permits to meet specific  requirements of such licenses, leases or permits; failure to satisfy certain  conditions in connection with the Company's debt and credit facilities;  breaches of confidentiality; costs of new technologies; alternatives to and  changing demand for petroleum products;  risks related to the Common Shares;  and risks pertaining to the Company's debt facilities.  The forward-looking statements included in this News Release are expressly  qualified by this cautionary statement. Athabasca does not undertake any  obligation to publicly update or revise any forward-looking statements except  as required by applicable securities laws.  Oil and Gas Information:  "BOEs" may be misleading, particularly if used in isolation.  A BOE conversion  ratio of six thousand cubic feet of natural gas to one barrel of oil  equivalent (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. As the value ratio between natural gas and crude  oil based on the current prices of natural gas and crude oil 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.  Test Results and Initial Production Rates: The well test results and initial production rates provided in this News  Release should be considered to be preliminary. Test results and initial  production rates disclosed herein may not necessarily be indicative of long  term performance or of ultimate recovery.    SOURCE  Athabasca Oil Corporation  Media and Financial Community  Matthew Taylor Vice President, Capital  Markets and Communications 1-403-817-9104   Financial Community Tracy Robinson Manager, Investor Relations 1-403-532-7446    To view this news release in HTML formatting, please use the following URL:  CO: Athabasca Oil Corporation ST: Alberta NI: OIL ERN CONF  
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