Highlights from the quarter and recent accomplishments:
- Corporate production – Third quarter production averaged 7,250 boe/d of which Light Oil accounted for 5,145 boe/d and Thermal Oil accounted for 2,105 bbl/d;
- Hangingstone – The initial production ramp-up continues to progress with current production in excess of 5,200 bbl/d. The Company’s updated Thermal Oil exit guidance is between 5,000 – 7,000 bbl/d (from 3,000 – 6,000 bbl/d);
- Duvernay – The Company is realizing significant drilling efficiencies utilizing a new fit for purpose rig and multi-well pad sites. A two well pad in the volatile oil window was rig released at Kabob East with drilling costs of $3.7 million and $2.8 million, respectively. The Company is now drilling a four well pad in the condensate rich window at Kaybob West with total drilling and completion (“D&C”) costs estimated to be approximately $10 million per well;
- Montney – At Placid, Athabasca is drilling a pad of three wells and estimates its costs will be approximately $8 million per well. The Company is planning to pipeline connect the Placid area to its extensive Kaybob infrastructure during the winter of 2016. This area is expected to provide significant future growth potential while also providing downside protection in an extended low commodity price environment;
- Guidance – The Company has reduced its 2015 capital budget by an additional 10% to $256 million, with upwardly revised corporate exit guidance between 12,000 – 15,000 boe/d (from 10,000 – 14,000 boe/d). The 2016 budget will be released in early December and in light of the commodity price environment the Company expects to implement a minimal capital program of less than $100 million to protect its balance sheet and liquidity position;
- Balance sheet position – Maintaining a strong financial position continues to be a top priority for Athabasca. As at November 1st, the Company has approximately $970 million of funding in place including approximately $790 million of cash, cash equivalents and proceeds from the last Phoenix Energy Holding Limited promissory note; and
- Cost structure – Subsequent to the quarter, Athabasca completed a cost structure review. Gross G&A costs are expected to total $40 – $45 million in 2016, representing an approximate 25% reduction from 2015 and a 55% reduction from 2014.
FINANCIAL AND OPERATING HIGHLIGHTS
|Three months ended
|Nine months ended
|($ Thousands, except per share and boe amounts)||2015||2014||2015||2014|
|Petroleum and natural gas volumes (boe/d)(2)||7,250||6,381||6,207||6,149|
|LIGHT OIL DIVISION|
|Petroleum and natural gas sales volumes (boe/d)||5,145||6,381||5,491||6,149|
|Light Oil operating income(1)||6,096||21,154||23,376||66,303|
|Light Oil operating netback(1) ($/boe)||12.88||36.03||15.60||39.49|
|THERMAL OIL DIVISION|
|Bitumen production (bbl/d) (including capitalized volumes) (2)||2,105||–||716||–|
|Bitumen sales volumes (bbl/d) (including capitalized volumes) (2)||1,956||–||660||–|
|Thermal Oil operating income (Loss)(1)(3)||(12,146||)||–||(12,146||)||–|
|Thermal Oil operating netback(1)(3)||(73.67||)||–||(73.67||)||–|
|CASH FLOWS AND FUNDS FLOW|
|Cash flow from operating activities||(17,933||)||30,371||(12,031||)||26,953|
|Cash flow from operating activities per share (basic & diluted)||(0.04||)||0.08||(0.03||)||0.07|
|Funds flow from operations(3)||(24,223||)||7,203||(17,035||)||21,482|
|Funds flow from operations per share (basic & diluted)||(0.06||)||0.02||(0.04||)||0.05|
|NET LOSS AND COMPREHENSIVE LOSS|
|Net loss and comprehensive loss||(38,241||)||(19,939||)||(92,398||)||(98,054||)|
|Net loss and comprehensive loss per share (basic & diluted)||(0.09||)||(0.05||)||(0.23||)||(0.24||)|
|Weighted average shares outstanding (basic & diluted)||403,396,304||401,718,942||402,933,671||401,564,195|
|FINANCING AND DIVESTITURES|
|Net proceeds from sale of Dover Investment||150,000||601,323||450,000||601,323|
|Net proceeds from sale of oil and gas assets||610||–||646||56,654|
|Net proceeds (repayment of) from long-term debt||(746||)||(630||)||(2,082||)||236,045|
|September 30, 2015||December 31, 2014|
|(1)||Refer to “Advisories and Other Guidance” beginning on page 19 of the Company’s Management’s Discussion and Analysis for the third quarter of 2015 (“MD&A”) for additional information on Non-GAAP Financial Measures.|
|(2)||For the three and nine months ended September 30, 2015, Thermal Oil bitumen production and sales volumes on a bbl/d basis represent all Hangingstone sales and production volumes (including capitalized volumes) for the period averaged over 92 days and 273 days, respectively.|
|(3)||Hangingstone Project 1 was ready for use in the manner intended by management on August 1, 2015. Amounts prior to August 1, 2015 have been capitalized and excluded from the calculation of the Thermal Oil Operating Loss and Netback.|
Athabasca’s production averaged 5,145 boe/d (48% liquids) in the third quarter of 2015, exceeding guidance of 5,000 boe/d. Quarterly volumes were impacted by approximately 370 boe/d due to the unplanned Alliance Pipeline shutdown in early August.
The Company deployed approximately $31 million of capital in Light Oil during the third quarter of 2015, which primarily related to the completion operations of wells from the prior winter’s program and the kick-off of second half operations.
Athabasca plans to bring four Duvernay wells (16-36-63-25W5, 12-28-62-23W5, 01-36-63-20W5 and 08-36-63-20W5) on stream during the fourth quarter of 2015. These wells were drilled previously and are currently soaking before being placed on production.
Athabasca commenced its drilling operations for the winter 2015/16 program in September. The Company’s core objectives for the program include demonstrating pad drilling cost efficiencies, and ongoing appraisal and delineation of the volatile oil window. These strategic objectives are expected to establish the strong economic potential and significant running room that Athabasca believes it has in this play.
Over the past three drilling seasons Athabasca has drilled 22 wells (17 horizontals, five verticals) in the Duvernay focused on retaining its core acreage, defining the thermal maturity windows and establishing confidence in reservoir performance. Approximately 95% of Athabasca’s core 200,000 acre land position at Kaybob is held into intermediate term, allowing considerable flexibility in the pace of development going forward.
Duvernay Volatile Oil Window
Athabasca continues to be encouraged by its results in the volatile oil window and the Company has drilled a total of nine horizontal and three verticals wells. Drilling has extended across the fairway with wells at Simonette, Kaybob West North, Kaybob East and Two Creeks.
At Kaybob East, the Company spud a two well pad at Section 5-65-18W5 in early September. These wells were rig released in 16 and 13 days, respectively. Well costs were $3.7 million and $2.8 million for an average cost of $3.25 million each. The Company is seeing significant drilling efficiencies utilizing a new fit for purpose rig and multi-well pad sites.
Completions operations on the two-well pad are currently underway and are designed to test higher proppant loading to determine its impact on productivity and ultimate recoveries. Athabasca expects to complete the 00/16-6-65-18W5 at ~1,100 lbs/ft consistent with recent design and the 02/16-6-65-18W5 at ~2,000 lbs/ft. A positive trend in productivity and ultimate recoveries has been observed by industry with increased proppant loading in both regional Duvernay data and also in other leading North American shale plays. Athabasca plans to place both wells on production in the first quarter of 2016 following a planned soak period.
Duvernay Condensate Rich Gas Window
Athabasca spud a four well pad in the condensate rich window in Section 36-63-20W5 (Kaybob West) in mid-October. Drilling operations are expected to be completed by early 2016 with an average lateral length of approximately 1,400 meters. Athabasca intends to complete the wells after break-up, with a planned on-stream date in the third quarter of 2016. Targeted well costs (D&C) are expected to be approximately $10 million with single well break-even costs of approximately US$35-40/bbl WTI.
At Kaybob West, Athabasca continues to gain confidence in extended production data and offsetting industry activity. Regionally industry has spud 95 wells to date with 39 wells with greater than one year of production history. The Company now has two wells with nine months (8-34-62-20W5, 118 mboe CTD 56% liquids) and 34 months (2-34-62-20W5, 458 mboe CTD 57% liquids) of extended production data and both wells continue to produce in the top quartile of industry wells.
The Company spud a three well Montney pad in September at Placid in Section 19-60-23W5 to follow up on two successful wells drilled in the winter of 2014/15. Athabasca intends to drill these three additional locations from the same surface location as the previously tested 9-26-60-24W5 well. The Placid area will also be pipeline connected to Athabasca’s extensive Kaybob infrastructure. This limited Montney development is expected to be economic in the current commodity environment and provides future growth potential while also providing downside protection in a prolonged low commodity price environment. Athabasca has approximately 25,000 acres of prospective Montney land in this area with no near term expiries.
At Hangingstone, the Company continues to make good progress with its initial production ramp-up. The Company now has 15 well pairs converted to SAGD production with an additional six well pairs expected to be converted in November. Reservoir response continues to meet management expectations and plant reliability has demonstrated over 99% runtime year to date. October production averaged 4,631 bbl/d and current volumes exceed 5,200 bbl/d.
Based on its performance to date, the Company is upwardly revising its Thermal Oil exit guidance to between 5,000 – 7,000 bbl/d (from 3,000 – 6,000 bbl/d, December average). The ramp-up to the project’s design capacity of 12,000 bbl/d in Q4 2016 remains on track with no additional development capital required and only minimal maintenance capital needed in the initial years. Through management of the existing SAGD producers and the additional available well pairs, Athabasca forecasts that the facility will have a relatively flat production profile for the first five to seven years once it reaches nameplate production.
The start-up of the dilbit pipeline to the Cheecham terminal remains on track for the end of the fourth quarter of 2015.
2015 Budget and Guidance
Athabasca’s has reduced its 2015 capital budget by an additional 10% driven by operational efficiencies and reducing non-productive capital. The consolidated budget stands at $256 million (excluding capitalized interest, G&A and land), down from $291 million.
|2015 Budget(1) ($ million)||Q1||Q2||Q3||Q4e||Full Year|
|Total Light Oil||$73||$8||$28||$75||$184|
|Hangingstone Project 1 (capital & capitalized start-up costs)||$44||$14||nil||nil||$59|
|Hangingstone expansion (pre-engineering)||1||nil||nil||nil||3|
|TOTAL CAPITAL SPENDING||$123||$23||$31||$79||$256|
|Capitalized Interest & G&A||$23||$20||$8||$2||$54|
|(1)||Figures may not add up due to rounding.|
Light Oil budget
The revised 2015 capital budget for Light Oil stands at $184 million (down from $203 million). Fourth quarter production is expected to average approximately 5,500 – 6,000 boe/d. Exit guidance is maintained at 7,000 – 8,000 boe/d (December average), however ongoing constraints on the TCPL pipeline system have the potential to impact volumes by up to 1,000 boe/d.
The fourth quarter 2015 program includes the following activity:
- Duvernay Volatile Oil Window:
- Completion of 00/16-6-65-18W5 and 102/16-6-65-18W5
- Begin producing 16-36-63-25W5 at Simonette
- Duvernay Condensate Rich Gas Window:
- Commence drilling operations on a four well pad in Section 36-63-20W5 at Kaybob West
- Begin producing 1-36-63-20W5 and 8-36-63-20W5 at Kaybob West
- Begin producing 12-28-62-23W5 at Saxon
- Placid Montney:
- Continue drilling operations on a 3 well pad
- Commence construction of the Placid inter-connect to Saxon
Thermal Oil budget
The revised 2015 Thermal Oil budget is $69 million (down from $82 million), reflecting reduced expenditures during Hangingstone Project 1 start-up and reduced spending on Hangingstone Expansion pre-engineering and other thermal assets. Thermal Oil capital expenditures are largely complete for the year.
The 2015 year-end Thermal oil exit production guidance has been upwardly revised to 5,000 – 7,000 bbl/d (from 3,000 – 6,000 bbl/d, December average).
Consolidated budget and financial outlook
Athabasca’s updated 2015 corporate year-end exit guidance is between 12,000 – 15,000 boe/d (from 10,000 – 14,000 boe/d, December average) based on a $256 million capital program.
Maintaining a strong financial position continues to be a top priority for Athabasca. As at November 1st, the Company has approximately $970 million of funding in place including approximately $790 million of cash, cash equivalents and proceeds from the last promissory note issued by Phoenix Energy Holdings Limited. The 2016 budget will be released in early December and the Company expects to implement a capital budget of less than $100 million. Minimal capital spending will be used as a lever to protect the Company’s balance sheet and liquidity position in light of the current commodity price environment.
A conference call to discuss the results will be held for the investment community on Thursday, November 5, 2015 at 7:30 a.m. MT (9:30 a.m. ET).
Conference Call Details:
Date: Thursday, November 5, 2015
Time: 7:30am MT (9:30am ET)
Dial In: 877-648-7976 (toll-free in North America) or 617-826-1698
Replay: 855-859-2056 (toll-free in North America) or 404-537-3406
Replay code: 61034860
About Athabasca Oil Corporation
Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development 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 www.atha.com.
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”, “target”, “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 Company’s 2015 year-end production guidance range from Hangingstone Project 1 (“HS1”); the Company’s 2015 year-end production guidance from its Light Oil division; the Company’s 2015 year-end guidance corporately; the timing of the ramp-up of production and of achieving plateau production from HS1; the timing of the start-up of the dilbit pipeline to the Cheecham terminal; HS1’s production profile for the first 5 – 7 years after reaching nameplate production; the expectation that an additional 6 well pairs in HS1 will be converted to SAGD production in November, 2015; the Company’s expectation that commodity prices will recover and the cash flow expected to be generated from the Company’s Thermal Oil and Light Oil divisions as a result; the improvements and efficiencies in Duvernay and Montney well drilling and completion costs expected to be realized by the Company, including from employing pad drilling; the expected drilling and completion costs of the Company’s Duvernay wells being drilled at Kaybob West and Montney wells being drilled at Placid; the timing of drilling and completion operations in the Company’s Light Oil division; the timing of the on-stream date the Company’s Light Oil division wells; the economic returns and growth potential expected to be realized from the Company’s Duvernay and Montney drilling programs; the timing of the construction of the Company’s Placid area pipeline and its connection to the Company’s Placid area wells; the benefits expected to be realized from the use of recovery technologies in the Company’s Light Oil division, including multi-stage, energized hybrid completion technology and the utilization of a high proppant loading completion design; the Company’s expected flexibility in its pace of development; the Company’s drilling plans, in particular, with respect to the Duvernay and Montney formations and the costs of such drilling operations; the Company’s estimated future commitments; the Company’s expected funding-in-place at the end of 2015; the Company’s business and financing strategies and plans; expectations regarding the Company’s 2015 capital budget; the Company’s expected 2016 budget; and the future allocation of capital.
With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices for petroleum and natural gas; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business and the effects that such regulatory framework will have on the Company, including on the Company’s financial condition and results of operations; Athabasca’s cash-flow break-even commodity price; geological and engineering estimates in respect of Athabasca’s reserves and resources; the applicability of technologies for the recovery and production of the Company’s reserves and resources; the Company’s ability to demonstrate the quality of its asset base and to build large-scale projects; 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 equipment in a timely and cost-efficient manner; the geography of the areas in which the Company is conducting exploration and development activities; and the Company’s ability to obtain equipment in a timely and cost-efficient manner.
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 Annual Information Form (“AIF”) dated March 11, 2015 that is available on SEDAR at www.sedar.com, including, but not limited to: fluctuations in market prices for crude oil, natural gas and bitumen blend; political and general economic, market and business conditions in Alberta, Canada, the United States and globally; changes to royalty regimes, environmental risks and hazards; alternatives to and changing demand for petroleum products; the Company’s credit rating; the substantial capital requirements of Athabasca’s projects and the ability to obtain financing for Athabasca’s capital requirements; operational and business interruption risks associated with the Company’s facilities; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the terms of contractual arrangements between Athabasca and such counterparties, including in compliance with the time schedules set out in such contractual arrangements, and the possible consequences thereof; aboriginal claims;
failure to obtain regulatory approvals or maintain compliance with regulatory requirements; 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; uncertainties inherent in estimating quantities of reserves and resources; changes to Athabasca’s status given the current stage of development; risks and uncertainties inherent in SAGD and other bitumen recovery processes; risks related to hydraulic fracturing, including those related to induced seismicity; 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; 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 costs could make Athabasca’s projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; environmental risks and hazards; failure to accurately estimate abandonment and reclamation costs; the potential for management estimates and assumptions to be inaccurate; long term reliance on third parties; reliance on third party infrastructure; seasonality; hedging risks; risks associated with maintaining systems of internal controls; insurance risks; claims made in respect of Athabasca’s operations, properties or assets; competition for, among other things, capital, 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; risks related to the Athabasca’s amended credit facilities; senior secured notes and term loans; and risks related to the Athabasca’s common shares.
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.
Media and Financial Community
Vice President, Capital Markets and Communications