CALGARY, ALBERTA–(Marketwired – July 30, 2015) – Athabasca Oil Corporation (“Athabasca” or the “Company”) (TSX:ATH) is pleased to report its second quarter 2015 financial and operating results.
Highlights from the quarter and recent accomplishments:
- Hangingstone achieved first oil in July with six well pairs recently converted to production. Steaming of the initial SAGD well pairs is continuing as planned. Reservoir response and plant reliability continues to meet management’s expectations;
- In July, Athabasca completed a two well pad at Kaybob West at an average cost of $11.0 million per well (drill & complete), below guidance of $12.5-13.5 million. The upcoming winter program includes a four well pad at Kaybob West with targeted well costs of $10-12 million;
- Quarterly Light Oil production averaged 5,459 boe/d exceeding guidance of 5,000 boe/d; and
- Athabasca remains committed to maintaining a strong financial positon. As of June 30, 2015, Athabasca had in excess of $1 billion of funding in place1 including approximately $580 million of cash, cash equivalents and short-term investments.
- The completion and tie-in of three previously drilled Duvernay wells (1-36-63-20W5, 8-36-63-20W5, 12-28-62-23W5);
- An on-stream date in Q4 of 16-36-63-25W5 at Simonette;
- Drilling and completion operations on a two well pad at Kaybob East in the volatile oil window (Surface 1-5-65-18W5); and
- Commencing drilling operations on a four well Duvernay pad at Kaybob West (Surface 4-36-63-20W5).
|1||Funding in place is defined as cash and cash equivalents, short-term investments, promissory notes (secured by irrevocable standby letters of credit from HSBC Canada) and undrawn credit facilities.|
|FINANCIAL AND OPERATING HIGHLIGHTS|
|Three months ended
|Six months ended
|($ Thousands, except per share and boe amounts)||2015||2014||2015||2014|
|Natural gas (Mcf/d)||17,038||16,563||17,579||18,282|
|Natural gas liquids (bbl/d)||622||823||586||688|
|Natural gas ($/Mcf)||2.85||5.01||2.82||5.67|
|Natural gas liquids ($/bbl)||32.51||85.46||29.21||83.37|
|Realized price ($/boe)||34.43||65.97||31.81||63.45|
|Operating expenses and transportation(1)($/boe)||(13.37||)||(14.53||)||(13.37||)||(14.93||)|
|Light Oil Operating Netback(2)($/boe)||21.51||46.12||16.84||41.36|
|LIGHT OIL OPERATING INCOME(2)|
|Petroleum and natural gas sales||17,105||34,626||32,630||69,272|
|Operating expenses and transportation expenses||(6,977||)||(8,380||)||(14,380||)||(17,859||)|
|Cash flow from operating activities||8,576||(18,641||)||5,922||(3,229||)|
|Cash flow from operating activities per share||0.02||(0.05||)||0.01||(0.01||)|
|Funds Flow from Operations(2)||5,085||5,016||8,201||14,483|
|Funds Flow from Operations per share (basic & diluted)||0.01||0.01||0.02||0.04|
|NET LOSS AND COMPREHENSIVE LOSS|
|Net loss and comprehensive loss||(29,044||)||(56,766||)||(54,156||)||(78,119||)|
|Net loss and comprehensive loss per share||(0.07||)||(0.14||)||(0.13||)||(0.19||)|
|Weighted average shares outstanding||402,981,471||401,334,034||402,698,520||401,144,341|
|Light Oil Division||14,959||14,847||94,200||92,296|
|Thermal Oil Division||33,118||90,556||101,685||248,514|
|Assets held for sale||–||2,600||–||6,600|
|As at($ Thousands)||June 30, 2015||December 31, 2014|
|1.||For the three and six months ended June 30, 2015, operating and transportation expenses include midstream revenues of $0.68/boe and $0.65/boe respectively (2014 – $1.44/boe and $1.43/boe respectively).|
|2.||Refer to “Advisories and Other Guidance” in the MD&A for additional information on Non-GAAP Financial Measures.|
|3.||For the three months ended June 30, 2015, capital expenditures include $1.6 million of capitalized G&A for Light Oil and $18.1 million of capitalized G&A and interest for Thermal Oil (June 30, 2014 – $2.2 million and $18.2 million respectively). For the six months ended June 30, 2015, capital expenditures include $4.0 million of capitalized G&A for Light Oil and $38.8 million of capitalized G&A and interest for Thermal Oil (June 30, 2014 – $4.5 million and $35.2 million respectively).|
|4.||Excludes $133.9 million promissory note due in August 2016.|
Athabasca’s production averaged 5,459 boe/d (48% liquids) in the second quarter of 2015 exceeding guidance of 5,000 boe/d and compared to 5,767 boe/d (52% liquids) in the second quarter of 2014. Light Oil operating netbacks were $21.51/boe compared to $46.12/boe in the second quarter of 2014.
The Company deployed approximately $13 million of capital in Light Oil during the second quarter of 2015 to complete the winter program and prepare for second half operations. Activity levels in the field were relatively light as the winter program concluded and operations were scheduled to resume following spring break-up.
Late this past winter, the Company elected to defer a portion of activity until the second half of this year in anticipation of a lower cost environment. Athabasca recently commenced second half operations which include the completion and tie-in of wells drilled during the winter program.
Over the past three drilling seasons Athabasca has drilled 20 wells (15 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 now held into intermediate term, allowing considerable flexibility in the pace of development going forward.
The core objectives for the winter 2015/16 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.
Duvernay Condensate Rich Gas Window
At Saxon, 15-15-62-23W5 (50% working interest) was completed in January and placed on production in early July. It had a restricted IP20 of 905 boe/d (gross, 57% liquids, 1,583 meter lateral). 12-28-62-23W5 was rig released in the first quarter and completions operations are scheduled for later in the third quarter. The well is expected to be placed on production before year-end.
In the Kaybob West area, Athabasca continues to gain confidence in extended production data and offsetting industry activity. 8-34-62-20W5 was placed on production in February 2015 and has averaged 535 boe/d over the past 150 days (58% liquids, approximately 1,325 meter lateral). The well continues to meet management’s internal type curve expectations and is tracking in the top quartile of regional industry wells.
In early July, completion operations commenced on a previously drilled two well pad in Section 36-63-20W5 (Kaybob West). Both wells were rig released last winter in approximately 35 days with drilling costs averaging $5.9 million each. Completions operations on 1-36-63-20W5 (1,970 meter lateral) and 8-36-63-20W5 (1,564 meter lateral) were deferred until the second half of 2015 in anticipation of lower service costs. The wells were completed for an average cost of $5.1 million each resulting in an average drill and complete cost of $11.0 million, below guidance of $12.5-13.5 million. Both wells are expected to be placed on production in the fourth quarter following a planned soak period.
The Company expects to see further cost improvements in the upcoming winter program through pad efficiencies (four well pad in Kaybob West), utilization of a new fit for purpose rig and further reductions from the current service cost environment. Drilling is planned to commence on this pad in the fourth quarter of 2015 with costs targeted between $10 – $12 million. This represents a significant reduction from previous single wells at approximately $15 million each and is expected to demonstrate the potential for even further reduced costs into the future.
Duvernay Volatile Oil Window
Athabasca continues to be encouraged by its preliminary results in the volatile oil window and the Company now has seven horizontal and three verticals wells drilled in the volatile oil window. Drilling has extended across the fairway with wells at Simonette, Kaybob West North, Kaybob East and Two Creeks.
At Kaybob East, the Company expects to spud a two well pad at Section 5-65-18W5 in September. The Company plans to test a high proppant loading completion design in one of the wells (approximately 2,000 lbs/ft compared to current design of approximately 1,000 lbs/ft). The goal is to assess the impact to productivity and ultimate recoveries, a positive trend seen in regional Duvernay data and also in other leading North American shale plays. Both wells are expected to be placed on production in Q1 2016.
At Simonette, 16-36-63-25W5 was completed in October 2014. Following a planned soak period the well was placed on production in March into a third party gas facility, but was subsequently shut-in due to road conditions impacting the trucking of liquids. The planned on-stream date has been deferred to the fourth quarter due to regional TCPL take-away constraints.
At Placid, the winter program included two Montney wells offsetting industry success. Both wells were drilled, completed and tested. The first well at 8-20-60-23W5 was placed on production through a third party facility in March and had a restricted IP30 of approximately 900 boe/d and a restricted IP120 of approximately 675 boe/d (58% liquids). Current production is restricted at approximately 600 boe/d. The Company remains encouraged by the initial production data and the well is maintaining strong pressures and liquids rates. The second well 9-26-60-24W5 was tested in early March.
Athabasca has approximately 25,000 acres of prospective Montney land in this area with no near term expiries.
In late March, the Company commenced steaming 15 of the planned 22 well pairs with an expected circulation phase of four to six months. During the second quarter, steaming of the initial well pairs continued as scheduled. Athabasca is monitoring the reservoir using fiber optic well bore sensors and a distributed pressure and temperature data network. Temperature fall-off tests coupled with reservoir monitoring are being used to confirm readiness of conversion to production. Initial temperature and pressure response in the reservoir, along with plant reliability, is in-line with management’s expectations.
The Company converted its first six well pairs to production in July 2015. The remaining nine well pairs are expected to be converted to production during the third quarter. Seven additional well pairs are planned to be put on circulation in the third quarter and converted to production prior to year-end.
Third party construction of transportation facilities is also substantially complete. The diluent supply pipeline is now operational and the start-up of the dilbit pipeline to the Cheecham terminal remains on track for the end of the fourth quarter of 2015.
Athabasca expects to give a more substantial update on preliminary production rates with third quarter results.
2015 Budget and Guidance
Athabasca’s revised 2015 capital budget stands at $291 million (excluding capitalized interest and G&A), down from $305 million reflecting a reduction in Thermal Oil expenditures.
|($ million)||Actuals||Actuals||Q3 – Q4||Full Year|
|Total Light Oil(2)||$77||$13||$112||$203|
|Hangingstone Project 1 (capital & capitalized start-up costs)(3)||$44||$14||$9||$67|
|Hangingstone expansion (pre-engineering)||1||nil||5||6|
|TOTAL CAPITAL SPENDING||$127||$29||$135||$291|
|Capitalized Interest & G&A||$23||$20||$17||$60|
|1.||Figures may not add up due to rounding.|
|2.||Q1 and Q2 2015 Light Oil Capital expenditures exclude $2.5 million and $1.6 million of capitalized G&A respectively.|
|3.||Operating expenses for Hangingstone Project 1 will be capitalized until Q3 2015 and will be expensed thereafter.|
|4.||Q1 2015 Thermal Oil Capital expenditures exclude $5.3 million of capitalized G&A and $15.5 million of capitalized interest. Q2 2015 thermal oil capital expenditures exclude $3.0 million of capitalized G&A and $15.1 million of capitalized interest.|
Light Oil budget
The 2015 capital budget for Light Oil remains unchanged at $203 million. The core objectives for the second half 2015 Light Oil program include demonstrating pad drilling cost efficiencies and ongoing appraisal work in the volatile oil window. Previously announced second half activity includes:
Athabasca’s third quarter production is expected to average approximately 5,000 boe/d and 2015 year-end Light Oil exit production guidance remains unchanged at 7,000 – 8,000 boe/d (December average).
Thermal Oil budget
The revised 2015 Thermal Oil budget is $82 million, down from $96 million, reflecting reduced expenditures on Hangingstone Expansion pre-engineering and other thermal assets. $67 million of capital is directed to the commissioning and ramp-up of Hangingstone Project 1. Thermal Oil capital expenditures are largely complete for the year. Operating costs associated with Project 1 will be capitalized until the third quarter of 2015.
The 2015 year-end Hangingstone exit production target remains between 3,000 – 6,000 bbl/d (December average). The project is anticipated to reach design capacity of 12,000 bbl/d by late 2016.
Consolidated budget and financial outlook
The 2015 corporate year-end exit target remains between 10,000 – 14,000 boe/d (December average) with total capital spend of $291 million (excluding capitalized interest and G&A).
Maintaining a strong financial position continues to be a top priority for Athabasca. Based on its current capital spending, production and cash flow outlook, Athabasca anticipates exiting 2015 with funding in place in excess of $800 million.
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 timing of the ramp-up of production and of achieving plateau production from Hangingstone Project 1; the expectation that 22 well pairs at Hangingstone Project 1will be put on circulation by the end of the third quarter of 2015 and on SAGD production 1 by the end of the 2015; the timing of the start-up of the dilbit pipeline to the Cheecham terminal in the fourth quarter of 2015; the expectation that the Hangingstone Project 1 will be ready for use in the manner intended by management in the third quarter of 2015; the Company’s 2015 third quarter and year-end production guidance from its Light Oil division; the reductions and efficiencies in Duvernay well drilling and completion costs expected to be realized by the Company, including from employing pad drilling; the drilling and completion operations in the Company’s Light Oil division in the second half of 2015; the Company’s 2015 third quarter and year-end production guidance from its Light Oil division and the Company’s 2015 year-end corporate production guidance; the expected timing of the Company’s Light Oil division wells coming on-stream; 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 anticipation of lower service costs in the second half of 2015; the benefits, including economic benefits, expected to be established by the Company from the Company’s 2015/2016 Duvernay drilling program; 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 timing of the Company’s well completion operations; the Company’s plans for, and results of, exploration and development activities; the Company’s estimated future commitments; the receipt of proceeds from the Promissory Notes; the Company’s expected funding-in-place at the end of 2015; the Company’s business and financing strategies and plans; expectations regarding the 2015 capital 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 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.
Athabasca Oil Corporation
Media and Financial Community
Vice President, Capital Markets and Communications