CALGARY, ALBERTA–(Marketwired – Nov. 10, 2016) – Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or “the Company”) is pleased to provide its 2016 third quarter results and an operations update. Athabasca has closed the previously announced upsized Contingent Bitumen Royalty (the “Royalty”) with Burgess Energy Holdings L.L.C. (“Burgess Energy”).
Athabasca’s strategy positions the Company for strong growth and financial sustainability into the future:
- Defined and Material Growth in Light Oil – a scalable operated Montney position and funded Duvernay development through the joint venture with Murphy Oil Company Ltd. (“Murphy”).
- Thermal Oil Leverage to Commodity Prices – continued ramp-up of Hangingstone Project 1, a low decline asset with significant cash flow torque and minimal capital requirements in the initial years of operations.
- Financial Sustainability – a current cash position of approximately $700 million and a $150 million net cash position (adjusted for outstanding debt).
Notable recent highlights include:
- Q3 2016 Operating Highlights – Corporate production averaged 11,848 boe/d (86% liquids), an increase of 63% year-over-year. Capital expenditures were approximately $18 million in the quarter.
- Upsized Contingent Bitumen Royalty – Athabasca has closed the upsized Royalty with Burgess Energy on its Thermal assets for an additional $128.5 million of cash consideration, bringing total proceeds received to $257 million. This unique Royalty does not encumber the assets at low commodity prices and further supports the significant long-term value of Athabasca’s Hangingstone and other thermal assets.
- Balance Sheet Update – Throughout 2016, Athabasca has successfully undertaken a series of transactions which have secured a funding model for its assets and position the Company to further deleverage and optimize its capital structure. Consideration for these transactions has totaled $743 million, including $524 million of cash proceeds. Athabasca’s final refinancing plans are underway and are expected to be completed prior to the end of 2016.
- Placid Montney – In the Light Oil division, Athabasca currently has two rigs active in Placid. The second half 2016 program includes drilling 12 development wells, the completion and tie-in of a four well pad and initial construction and long lead commitments on an oil battery to accommodate mid-term growth plans. The Montney program is anticipated to drive strong economic growth through the first half of 2017 as the wells are placed on production.
- Greater Kaybob Duvernay – The joint venture is finalizing 2017 operating plans which will be released in conjunction with the Company’s corporate budget in December. Murphy is expected to spud a two well pad in the gas condensate window in Q4 2016 with on-stream timing in late Q1 2017. The joint development agreement contemplates approximately $1 billion of Duvernay gross investment over the next four to five years of which Athabasca’s net capital exposure is approximately $75 million.
- Hangingstone – Third quarter volumes averaged 8,830 bbl/d and September production averaged 8,922 bbl/d. The project has successfully recovered from downtime during the Fort McMurray wildfires, with updated reservoir simulations predicting reaching design capacity of 12,000 bbl/d in 2018 and no anticipated impact to long-term oil recoveries.
FINANCIAL AND OPERATING HIGHLIGHTS
|3 months ended Sept. 30||9 months ended Sept. 30|
|($ Thousands, except per share and boe amounts)||2016||2015||2016||2015|
|Petroleum and natural gas volumes (boe/d)||11,848||7,250||12,098||6,207|
|LIGHT OIL DIVISION|
|Petroleum and natural gas sales volumes (boe/d)||3,018||5,145||5,019||5,491|
|Light Oil operating income1||$||5,511||6,096||17,632||23,376|
|Light Oil operating netback1 ($/boe)||$||19.85||12.88||12.82||15.60|
|Recovery of capital-carry through capital expenditures||$||(4,286)||–||(5,760)||–|
|THERMAL OIL DIVISION|
|Bitumen production (bbl/d)||8,830||2,105||7,079||716|
|Bitumen sales volumes (bbl/d)||9,744||1,956||7,138||660|
|Thermal Oil operating income (loss)1, 2||$||(6,088)||(12,146)||(41,079)||(12,146)|
|Thermal Oil operating netback1, 2 ($/bbl)||$||(6.80)||(73.67)||(20.99)||(73.67)|
|CASH FLOWS AND FUNDS FLOW|
|Cash flow from operating activities||$||(18,990)||(17,933)||(51,297)||(12,031)|
|Cash flow from operating activities per share (basic & diluted)||$||(0.05)||(0.04)||(0.13)||(0.03)|
|Funds flow from operations1||$||(15,778)||(24,223)||(84,622)||(17,035)|
|Funds flow from operations per share (basic & diluted)||$||(0.04)||(0.06)||(0.21)||(0.04)|
|NET LOSS AND COMPREHENSIVE LOSS|
|Net loss and comprehensive loss||$||(33,032)||(38,241)||(157,331)||(92,398)|
|Net loss and comprehensive loss per share (basic & diluted)||$||(0.08)||(0.09)||(0.39)||(0.23)|
|Weighted average shares outstanding (basic & diluted)||405,556,092||403,396,304||405,357,248||402,933,671|
|FINANCING AND DIVESTITURES|
|Promissory note proceeds||$||133,892||150,000||133,892||450,000|
|Cash proceeds from sales of assets||$||(1,944)||610||390,394||646|
|Repayment of long-term debt||$||–||(746)||(285,441)||(2,082)|
|Derivative proceeds upon repayment of long-term debt||$||–||–||40,956||–|
|As at ($ Thousands)||Sept. 30,
|BALANCE SHEET ITEMS|
|Cash and cash equivalents||$||535,477||559,487|
|Capital-carry receivable (current & LT portion – discounted)3||$||188,448||–|
|1) For additional information on Non-GAAP Financial Measures, refer to “Advisories and Other Guidance” in Athabasca’s Management Discussion & Analysis dated November 10, 2016 which is available on SEDAR at http://www.sedar.com/.|
|2) Negative Operating Netbacks are customary during ramp-up of a SAGD project as revenues from lower initial production are more than offset by operating and transportation costs which are largely fixed in nature regardless of production volumes. Athabasca anticipates that operating and transportation costs per barrel from Hangingstone Project 1 will continue to improve as production increases.|
|3) $213.5 million undiscounted capital carry.|
Production averaged 3,018 boe/d (46% liquids) in the third quarter of 2016. Capital expenditures totaled $14.6 million (net of capital carry of $4.3 million) with activity primarily focused on commencing development at Placid.
Greater Placid Area- (70% Montney working interest; Q3 1,818 boe/d net)
The Company has established a scalable, operated position which has competitive returns relative to other North American plays. Activity to date has defined a higher liquids trend on Athabasca’s acreage with high initial free liquids cuts between 200 – 300 bbl/mmcf.
In July, the Company spud a four well pad at surface location 7- 30 -60-23W5 (“7-30”). The pad was rig released in September achieving regional pace setter results with drill times averaging approximately 17 days spud to total depth with average lateral lengths of 2,415 meters. This marks a significant improvement over the 2014/15 winter drilling season average of 23 days. On the 7-30 pad the Company estimates average drilling costs of C$3.15 million per well, down 15% from the previous year’s program. Completion operations commenced in late October which will test a new completion design. The Company is planning two wells with a standard ball drop design and trialing two wells with a plug and perf system. The plug and perf completion design allows more discrete completion intervals and has shown an extended production uplift in other liquids rich Montney analogs. Average completion cost per well is estimated at C$3.1 million for the ball drop design and C$4.3 million for the plug and perf design. The pad is expected to be placed on production before year-end.
The Company currently has two drilling rigs active at surface locations 12-19-60-23W5 (“12-19”) and 16- 30 -60-23W5 (“16-30”). Both four well pads are expected to be rig released before year-end with completions operations to follow in Q1 2017 and on-stream timing before spring breakup. Athabasca has operational flexibility to run between one to two rigs through the balance of the winter program.
Extended production data from last winter’s program continues to support management’s type curve expectations with the wells exhibiting modest declines as initial rates were restricted during the clean-up period. The latest five wells have had average IP30s of 805 boe/d (64% liquids), IP90s of 686 boe/d (56% liquids) and IP180s of 587 boe/d (53% liquids).
The Company remains on track to commission an oil battery at Placid in April 2017 which will accommodate liquids handling through 2018.
As Placid operations transition to pad development the play is expected to drive competitive capital efficiencies. Athabasca will remain focused on economically growing production while delineating both Montney intervals and growing the aerial extent of the play. With no near-term land expiries and operated egress, Placid is set up with significant flexibility to control the pace of development going forward. Athabasca has high-graded exposure to approximately 25,000 gross acres of prospective Montney land. The development inventory is estimated between 150 – 200 gross locations which could drive organic growth in excess of five years under an accelerated two rig development scenario.
Greater Kaybob Area – (30% Duvernay working interest; Q3 1,200 boe/d net)
Athabasca and Murphy closed the $486 million light oil joint venture on May 13, 2016. Integration of operations is substantially complete with Murphy now operating wells in the field.
At Kaybob West, in the condensate rich gas window, the Company completed fracturing operations in July on a previously drilled four well pad at Section 36-63-20W5. With input from Murphy, completion intensity on this pad was increased to approximately 2,000 lbs/ft, up from the prior design of approximately 1,100 lbs/ft. Final drill and completion costs were C$8.3 million per well (previously estimated at ~C$9.5 million) with average drilled lateral lengths of approximately 1,370 meters. Through September, the wells were placed on production sequentially with Murphy operating. The wells have been heavily restricted with IP30s averaging 253 boe/d (72% liquids) and have since increased to in excess of 400 boe/d (62% liquids). In line with production practices employed by Murphy in the liquids rich portions of the Eagle Ford, the wells were initially restricted to assess enhancement of liquids recoveries in the higher CGR regions of the Duvernay. Murphy intends to further optimize well design in the 2017 program by testing higher proppant intensity in longer laterals.
Joint venture drilling operations are expected to commence in the fourth quarter with a two well pad at surface location 01-18-64-20W5 offsetting the 1-7-64-20W5 drilled by Athabasca in 2014. The joint development agreement contemplates approximately $200 million of gross capital ($15 million net) in 2017 with the majority of spending directed towards drilling and completion operations. These plans include a mix of continued resource delineation in the volatile oil window and pad operations in lower risk more defined areas of the play. More details on activity levels will be provided with the 2017 budget in December.
The joint development agreement is designed to maximize land retention, delineate the volatile oil window and progress the entire asset to the self-funding stage post the initial carry period. The $219 million capital carry amount ($213.5 million currently remaining) will minimize Athabasca’s financial exposure in the mid-term, with Murphy funding 75% of the Company’s 30% working interest on the first $1 billion of investment ($75 million net exposure) over the next four to five years in this play.
Thermal Oil – Hangingstone
In the Thermal Oil Division, Hangingstone Project 1 is approximately fifteen months into its production ramp-up with 23 well pairs converted to SAGD production.
Bitumen production for the third quarter averaged 8,830 bbl/d with volumes recovering from three weeks of downtime during the Fort McMurray wildfires in May. Both water rates and oil cuts have returned to pre-fire conditions. The Company is progressing planned pump changes moving the field to ESPs (electrical submersible pumps) to manage higher emulsion rates as the steam chambers mature and as production ramps up. September production averaged 8,922 bbl/d with a steam oil ratio (“SOR”) of 4.6.
Athabasca has completed an update to the Company’s internal reservoir simulation that is based on a detailed geological interpretation of the reservoir from extensive delineation drilling prior to sanctioning the project, continuous temperature and pressure monitoring across the field and an annual 4D seismic monitoring program. Data supports that the reservoir is bounded, pressure has stabilized and steam conditions are continuing to grow vertically which will drive higher oil volumes and lower SORs with time. The revised model reflects continued but slower vertical steam chamber growth than previously expected with the facility projected to achieve design capacity of 12,000 bbl/d in 2018. This revised outlook is not anticipated to impact long-term oil recoveries.
Upsized Contingent Bitumen Royalty
On November 3, 2016, Athabasca announced the upsizing of the Royalty with Burgess Energy on its Thermal assets. The transaction closed on November 10, 2016 and the Company received an additional $128.5 million of cash consideration, bringing total proceeds received to $257 million. The upsized Royalty further supports the significant long-term value of Hangingstone and Athabasca’s other thermal assets.
The Royalty will be calculated on a sliding scale ranging from 0% – 12% (previously 0% – 6%) of Athabasca’s realized bitumen price (C$) for each Thermal Oil asset (see table below). The realized bitumen price is to be determined net of diluent, transportation and storage costs. The Royalty has been structured so that the assets will not be encumbered at lower pricing levels. For example, at Hangingstone, oil prices would have to reach approximately US$75/bbl WTI (at nameplate capacity of 12,000 bbl/d) before the first 2% Royalty is triggered. At this pricing level, Hangingstone Project 1 is estimated to have an annual operating netback of approximately $120 million (net of a $4 million Royalty). The Royalty is not expected to materially impact economics of future Hangingstone expansion phases or other future Thermal Oil development projects and there are no associated commitments for future development.
|Hangingstone||Other Thermal Assets|
|Realized Bitumen Price||Royalty||Implied WTI*||Realized Bitumen Price||Royalty||Implied WTI*|
|Below $50/bbl||0%||Below $60/bbl||0%|
|$50/bbl to $69.99/bbl||2%||$75-91||$60/bbl to $79.99/bbl||2%||$78-94|
|$70/bbl to $89.99/bbl||4%||$91-108||$80/bbl to $99.99/bbl||4%||$94-110|
|$90/bbl to $109.99/bbl||6%||$108-124||$100/bbl to $119.99/bbl||6%||$110-126|
|$110/bbl to $129.99/bbl||8%||$124-141||$120/bbl to $139.99/bbl||8%||$126-142|
|$130/bbl to $149.99/bbl||10%||$141-157||$140/bbl to $159.99/bbl||10%||$142-159|
|$150/bbl and above||12%||>$157||$160/bbl and above||12%||>$159|
|* Implied WTI based on a 0.8 US$/C$ FX assumption & US$15/bbl heavy differential.|
|Royalties calculated & payable on a monthly basis.|
2016 Budget and Outlook
In the Light Oil division, Athabasca maintains its $102 million net capital budget which reflects the previously announced expanded Montney program at Placid. Annual Light Oil production is estimated at approximately 4,500 boe/d and the Company anticipates strong Montney growth through the first half of 2017 as the wells are placed on production.
In the Thermal Oil division, the wildfire impact, unplanned maintenance downtime year to date and planned pump changes in Q4 has impacted production volumes with annual guidance estimated at approximately 7,300 bbl/d on an unchanged capital budget of $11 million.
The 2017 budget will be announced in December.
|2016 Capital Budget1 ($ millions)||Full Year|
|Greater Kaybob2 (Duvernay)||$8|
|Greater Placid3 (Montney)||94|
|Total Light Oil||$102|
|TOTAL CAPITAL SPENDING||$121|
|1) Figures may not add up due to rounding.|
|2) Greater Kaybob net capital reflects Athabasca’s 30% interest following the application of the capital carry (Murphy funds 75% of Athabasca’s 30% working interest).|
|3) Greater Placid net capital reflects Athabasca’s 70% working interest.|
|2016 Operational & Financial Guidance||Full Year|
|LIGHT OIL (net)|
|Liquids Weighting (%)||49%|
|Operating Income ($MM)||~$23|
|Operating Netback ($/boe)||~$14|
|Bitumen Production (bbl/d)||7,300|
|Operating Income ($MM)||~($49)|
|Production (boe/d)||11,800 (~81% liquids)|
|Funds Flow from Operations ($MM)||~($103)|
|Year-end Cash & Equivalents1 ($MM)||~$620|
|COMMODITY ASSUMPTIONS (strip pricing as at Oct. 5, 2016)|
|Edmonton Par (C$/bbl)||$51.43|
|Western Canadian Select (C$/bbl)||$37.29|
|AECO Gas (C$/mcf)||$2.03|
|1) Excludes $104 million of restricted cash.|
Throughout 2016, Athabasca has successfully undertaken a series of transactions, including the Murphy joint venture and the Thermal Oil Royalty, which have secured a funding model for its assets and position the Company to further deleverage and optimize its capital structure in the coming months. Consideration for these transactions has totaled $743 million, including $524 million of cash proceeds. The Company now has a cash balance of approximately $700 million (excluding $104 million of restricted cash) with a net cash position of approximately $150 million (adjusted for outstanding debt). The Company also has approximately $213.5 million of further funding available through the capital carry balance with Murphy on its Duvernay joint venture lands.
Since the beginning of 2016, Athabasca has reduced its term debt outstanding by approximately $250 million, and plans to direct the proceeds from the upsizing of the Royalty towards debt repayment, further deleveraging the Company and reducing borrowing costs. Athabasca’s final refinancing plans are underway and are expected to be completed prior to the end of 2016. The Company is targeting a capital structure that is well aligned with its future strategic plans and provides a multi-year funding outlook with significant flexibility for the future.
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.