CALGARY, ALBERTA–(Marketwired – Dec. 14, 2016) –
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Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or “the Company”) is pleased to announce that is has entered into agreements with Statoil ASA (“Statoil”) and its wholly owned subsidiary Statoil Canada Ltd. to acquire its Canadian Thermal Oil assets for consideration of $435 million cash, 100 million common shares and contingent value payments triggered at oil prices above US$65/bbl WTI. The acquired assets include the operating Leismer Thermal Oil Project (currently producing 24,000 bbl/d), the delineated Corner lease and related strategic infrastructure. The acquisition establishes Athabasca as an intermediate oil weighted growth company with a production base of approximately 40,000 boe/d (2017e). Upon closing, cash flow from the low decline production base will support thermal sustaining capital requirements and economic growth in the liquids rich Montney and Duvernay resource plays.
Mr. Robert Broen, Athabasca’s President and Chief Executive Officer said, “This transaction is transformational for Athabasca and establishes scale with top tier thermal assets and people. We are pleased to have Statoil, a global energy leader, as an investor in the Company. Shareholders are positioned with a unique and compelling return proposition. Athabasca has the financial strength to drive oil weighted growth at competitive metrics in the current environment.”
Mr. Paul Fulton, President, Statoil Canada, said “We are pleased to announce this agreement with Athabasca. The transaction allows Statoil to redeploy proceeds to our global portfolio of opportunities. We firmly believe Athabasca is very well placed to continue the development of these assets.”
The acquisition complements Athabasca’s strategy and positions the Company for strong growth and financial sustainability into the future:
- Light Oil: Defined and Material Growth – A scalable operated Montney position and funded Duvernay development through the joint venture with Murphy Oil Company Ltd. (“Murphy”).
- Thermal Oil: Leverage to Oil Prices – A large low decline asset base accelerates free cash flow generation with future low risk expansion options.
- Financial Sustainability – Maturing cash flow profile with a significantly stronger sustainability metrics. A diverse asset base provides flexibility in future capital allocation decisions.
Throughout 2016, Athabasca has executed a number of strategic transactions aimed at securing a funding model for its core plays and monetizing long dated resources. These transactions have helped Athabasca transform into a unique intermediate oil Company with meaningful exposure to several of the largest resource plays in Western Canada.
The Acquisition
Asset Highlights
Statoil’s Canadian Thermal Oil assets include the producing Leismer lease, delineated Corner lease and strategic regional infrastructure.
The Leismer project was commissioned in 2010 with current production of approximately 24,000 bbl/d. The project has proved reserves in place to support a flat production profile for over 30 years and a reserve life index approximately 70 years (proved plus probable). Athabasca intends to maintain a stable production base for the foreseeable future. The Leismer and Corner leases have received regulatory approval for future development phases up to a combined 80,000 bbl/d.
The assets are high quality and resilient to lower commodity prices. Leismer’s current steam oil ratio (“SOR”) of ~2.7x ranks it as one of the lowest among operating projects in the basin. Operating income break-even is estimated at ~US$44/bbl WTI. In Q4 to date, the assets generated approximately $9 million of operating income per month at an average WTI price of approximately $48/bbl. Over the next five years, the Company estimates that Leismer will generate free cash flow in excess of $575 million and $325 million under US$60/bbl WTI and strip commodity forecasts (Dec. 3, 2016), respectively.
Strategic infrastructure includes ownership of dilbit and diluent pipelines from Leismer to Cheecham Terminal, 300,000 barrels of storage capacity at the Cheecham Terminal and access to multiple sales points with marketing agreements on the Enbridge Waupisoo and optionality on the Kinder Morgan Trans Mountain pipeline expansion.
Strategic Rationale
- Transitions Asset Portfolio to a More Sustainable Business Model – Throughout 2016, Athabasca has significantly strengthened its balance sheet through the Light Oil joint venture with Murphy ($486 million total consideration) and the Thermal Oil Contingent Bitumen Royalty granted to Burgess Energy ($307 million cash consideration; amended terms outlined in the financing section below). These transactions secured creative funding for Athabasca’s core plays and established the financial flexibility to acquire very high quality assets.
- Bolsters Sustainability Metrics and Accelerates Free Cash Flow Generation – The assets immediately drive a larger cash flow base and accelerate the Company’s transition to sustainable free cash flow generation, which is expected in early 2018 at US$60/bbl WTI or early 2019 on strip pricing (Dec. 3).
- Significant Flexibility in Capital Allocation – Upon closing, cash flow from the low decline production base will support thermal sustaining capital requirements and meaningful economic growth in the liquids rich Montney (150 – 200 locations) and Duvernay (1,500 locations) resource plays.
- Highly Accretive to Cash Flow and Reserves Per Share – The acquisition is forecasted to be highly accretive on key operating and financial metrics within the Company’s five year forecast period. Specifically, 275% and 60% accretive on 2017 and 2018 cash flow per basic share (strip pricing Dec. 3) respectively and approximately 250% accretive on proved plus probable reserves per share.
- Scale in the Thermal Oil Division with Low Risk Expansion Opportunities – A 33,000 bbl/d low decline thermal production base lowers operating break evens and improves resiliency to challenging oil prices. The Company has regulatory approval for expansions up to a combined 80,000 bbl/d from the Leismer, Hangingstone and Corner leases.
- Strengthened Reserve Base – The assets enhance the Company’s reserve base by adding 31 mmbbl proved developed producing, 291 mmbbl proved and 856 mmbbl proved plus probable reserves. The Company’s estimate for corporate pro forma proved plus probable reserves is approximately 1,100 mmbbl with a 75 year reserve life index based on 2017 forecasted production.
- Strategic Thermal Oil infrastructure – The assets include key strategic infrastructure and marketing agreements which provide access to multiple end markets. Combined with Hangingstone volumes, the company will have opportunities for commercial synergies in the future.
- Best-in-Class Innovation and Sustainable Development – Statoil is recognized as an industry leader in energy efficiency and reducing carbon dioxide emissions per barrel of produced oil. Statoil has invested significantly in technology for application on Thermal projects to increase development efficiency and lower overall carbon footprint. Leismer and Corner are top tier leases which will improve Athabasca’s overall asset quality with a net benefit to the Company’s already high environmental standards.
Acquisition Mechanics and Metrics
Consideration for the Acquisition is as follows:
- Cash – $435 million funded through cash on hand.
- Equity – 100 million common shares of Athabasca. Statoil will become an investor in Athabasca with just under 20% basic ownership.
- Contingent Value Payments – Athabasca has agreed to a series of contingent value payments over a four year term ending in 2020. The annual payment is calculated as: 33% of Leismer Bitumen Production x Oil Factor (Monthly Average WTI less US$65/bbl adjusted for inflation). The payment is capped at $75 million annually and $250 million over the term. For context, at US$65/bbl the Leismer asset is expected to have an operating income of approximately $215 million with no contingent value payment, at US$75/bbl an estimated operating income of approximately $315 million with a $39 million contingent value payment. Under strip commodity pricing the Company does not expect to make any contingent payments over the four year term.
The Acquisition will have an effective date of January 1, 2017 with closing anticipated in the first quarter of 2017. The Acquisition is subject to usual closing conditions and regulatory approvals, including TSX approval, and is not subject to a financing condition.
| ACQUISITION HIGHLIGHTS AND METRICS | |
| Purchase Price1 | $582MM |
| Current Production | ~24,000 bbl/d |
| Proved Reserves & NPV10 BT2 | 291 mmbbl & $1,549MM |
| Proved plus Probable Reserves & NPV10 BT2 | 856 mmbbl & $2,574MM |
| Contingent Resource (Best Estimate Unrisked)3 | 628 mmbbl |
| 2017e Cash Flow4 | $90 – 105MM |
| $/bbl/d Current Production | ~$24,000/bbl/d |
| $/boe Proved + Probable | $0.68/boe |
| P/CF | ~5.8x |
| Notes: | |
| 1. | A $582 million purchase price reflects $435 million cash and 100 million Athabasca common shares at $1.47 per share. |
| 2. | Preliminary GLJ & Associates reserve evaluation as at November 30, 2016. |
| 3. | Preliminary GLJ & Associates resource evaluation as at November 30, 2016. Best Estimate Contingent Resources Unrisked. |
| 4. | Management estimate based on preliminary 2017 production and cash flow based on December 3, 2016 strip price outlook. |
Acquisition Financing and Balance Sheet Update
The cash component of the purchase price will be sourced from existing cash balances. In 2017, the Company intends to access the capital markets to refinance its Senior Secured Second Lien Notes (the “Notes”). Athabasca also notes the following:
- Existing Cash on Hand – Athabasca’s current cash balance is approximately $760 million.
- Expanded Credit Facilities – The Company is in discussions with its banking syndicate to establish a new reserve based loan facility. The acquisition significantly enhances the Company’s cash flow profile and proved developed producing reserve base.
- Hedging – In conjunction with the acquisition, the Company is evaluating hedging opportunities and plans to hedge up to 50% of 2017 corporate production. The hedge program will be designed to protect a base level of cash flow to support capital plans and has the potential to expand reserve based loan facilities.
- Amended Contingent Bitumen Royalty – The Company is amending its existing Contingent Bitumen Royalty (the “Royalty”) with Burgess Energy Holdings LLC (“Burgess”) for additional cash proceeds of $50 million. The amendment includes converting the existing sliding scale to a linear scale and is based on the Western Canadian Select (“WCS”) benchmark. The minimum trigger for the Royalty is US$60/bbl WCS for Hangingstone and US$70/bbl WCS for the Company’s other Thermal assets (Dover West, Birch and Grosmont). Following close, which is anticipated in conjunction with closing of the Statoil acquisition or earlier, total cash proceeds raised through the Royalty will be $307 million. There is no Royalty assigned to the newly acquired Leismer or Corner assets.
- Anchor 2017 Notes Refinancing Commitment – The Company has advanced discussions with a number of existing and potential investors regarding its refinancing plans and has secured an anchor commitment of $125 million towards a new debt instrument.
The acquisition significantly bolsters Athabasca’s credit quality and cash flow profile. The Company forecasts a low decline production base of approximately 40,000 boe/d (~90% liquids, 2017e) and intends to optimize its capital structure to ensure a multi-year funding outlook. The Company anticipates net debt to cash flow metrics of less than <2.5x in 2018 and much lower in subsequent years.
Outlook
The Company maintains significant flexibility to adapt its capital expenditures to external market conditions.
In the Light Oil division, Athabasca intends to complete its winter program in the Montney at Placid which will include the drilling of 20 horizontal wells and the completion and tie-in of 12 wells by spring break-up. Capital for the Montney is forecasted at approximately $115 – 125 million. In the Duvernay, 2017 joint venture plans are being finalized with Murphy and the joint development agreement contemplates approximately $200 million of gross capital ($15 million net) with the majority of spending directed towards drilling and completion operations across the acreage base.
In the Thermal Oil division, activity will be focused on maintaining a stable production base on the acquired assets and the continued ramp-up of Hangingstone to design capacity. 2017 Capital is expected to be approximately $90 – 110 million, with the majority on the newly acquired Leismer asset.
The Company will release its official capital budget and guidance in conjunction with closing of the acquisition.
| Preliminary 2017 Operational & Financial Guidance | Full Year | |
| CORPORATE (net) | ||
| Production (boe/d) | 38,000 – 42,000 | |
| Liquids Weighting (%) | ~90% | |
| Funds Flow from Operations1 ($MM) | ~$90 | |
| THERMAL OIL | ||
| Bitumen Production1 (bbl/d) | 31,500 – 34,500 | |
| Operating Income ($MM) | ~$90 | |
| LIGHT OIL | ||
| Production1 (boe/d) | 6,500 – 7,500 | |
| Operating Income ($MM) | ~$80 | |
| COMMODITY ASSUMPTIONS (strip pricing as at Dec. 3, 2016) | ||
| WTI (US$/bbl) | $54.25 | |
| Edmonton Par (C$/bbl) | $68.00 | |
| Western Canadian Select (C$/bbl) | $50.50 | |
| AECO Gas (C$/mcf) | $3.15 | |
| FX (US$/C$) | 0.75 | |
| Notes: | |
| 1. | Reflects full year impact of the Statoil asset acquisition. Jan. 1, 2017 effective date with closing expected in Q1 2017, volumes and cash flows will be adjusted to reflect a closing adjustment. |
| 2. | Corporate funds flow based on mid-points of guidance and debt refinancing assumptions similar to current capital structure. |
Advisors
Goldman Sachs Canada Inc. and TD Securities Inc. are acting as financial advisors for Athabasca in connection with the acquisition.
Conference Call
A conference call to discuss the acquisition will be held for the investment community on Thursday, December 15, 2016 at 7:00 a.m. MT (9:00 a.m. ET).
| Conference Call Details: |
| Date: Thursday, December 15, 2016 |
| Time: 7:00am MT (9:00am ET) |
| Dial In: (877) 291-4570 (toll-free in North America) or (647) 788-4919 |
| Replay: (800) 585-8367 (toll-free in North America) or (416) 621-4642 |
| Replay code: 38582031 |
| Webcast Details: |
| http://www.gowebcasting.com/8268 |
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.
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”, “believe”, “contemplate”, “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 benefits expected to be realized by the Company from its acquisition of Canadian Thermal Oil Assets from Statoil ASA (the “Statoil Transaction”), including the expected terms and conditions of the Statoil Transaction; satisfaction of all parties to the conditions to closing and the timing and completion of the Statoil Transaction; the expected cash consideration, share consideration and contingent value payments over a four year term ending in 2020 pursuant to the Statoil Transaction; the impact on the Company’s financial position and balance sheet strength and the benefits expected to be realized from the Statoil Transaction and future performance and characteristics of the assets including their high quality and resilience to lower commodity prices; the Company’s expectation that the Statoil Transaction will significantly bolster its credit quality and cash flow profile; the Company’s estimation of pro forma proved plus probable reserves; the Company’s expectation that the low decline production base in the Leismer, Hangingstone and Corner lands will support the thermal sustaining capital requirements and meaningful economic growth in the Montney and Duvernay resource plays; the long term marketing agreements with Enbridge Waupisoo and future opportunities for commercial synergies such as optionality on the Kinder Morgan Trans Mountain pipeline expansion; the availability of key strategic infrastructure and regulatory approvals for leases; scope and timing of drilling, completion and commissioning operations in the Company’s Light Oil division and the costs of such drilling and completion operations; the 2017 joint venture plans with Murphy; the scope of activity in the Company’s Thermal Oil division including the ramp-up of Hangingstone to design capacity; and the Company’s plans to finance the Statoil Transaction including expanding credit facilities, hedging, amending Royalty and note financing.
With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: that the Statoil Transaction will close on terms and on the timing expected; that the required regulatory approvals and satisfaction of all conditions to closing of the Statoil Transaction will be obtained and on the time frames contemplated; that the Statoil Transaction will be successfully completed and the parties and their securityholders will obtain the anticipated benefits of the Statoil Transaction; 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; the Company’s financial and operational flexibility; the Company’s financial sustainability, the Company’s ability to accelerate development when prices recover; 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 10, 2016 that is available on SEDAR at www.sedar.com, including, but not limited to: failure to complete the Statoil Transaction in all material respects in accordance with the asset purchase and sale agreement; the inability to obtain regulatory, TSX, Competition Act (Canada) and other required approvals in connection with the Statoil Transaction; 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 potential for management estimates and assumptions to be inaccurate; dependence on Murphy as the Company’s joint venture participant in the Company’s Duvernay and Montney assets; the dependence on Murphy as the operator of the Company’s Duvernay assets;
the substantial capital requirements of Athabasca’s projects and the ability to obtain financing for Athabasca’s capital requirements and for the Statoil Transaction; 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 respect of the Statoil Transaction and the Royalty, and the possible consequences thereof; the potential for adverse consequences in the event that the Company defaults under the agreement in respect of the Statoil Transaction; long term reliance on third parties; 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; litigation risk; 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; 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 Athabasca’s amended credit facilities and senior secured notes; and risks related to Athabasca’s common shares.
For important additional information regarding Athabasca’s reserves and resources estimates and the evaluations that were conducted by GLJ and D&M, please see “Independent Reserve and Resource Evaluations” in the Company’s most recent AIF dated March 10, 2016 that is available on SEDAR at www.sedar.com. The forward-looking statements included in this News Release are expressly qualified by this cautionary statement. The forward looking statements contained herein are made as of the date hereof and 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.
Drilling Locations: the ~150 – 200 Montney inventory referenced in this News Release includes 8 probable undeveloped locations, with the balance being unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. as of December 31, 2015 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have been identified by management as an estimation of Athabasca’s multi-year drilling activities expected to occur over the next two decades based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, oil and natural gas prices, provincial fiscal and royalty policies, costs, actual drilling results and additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
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Matthew Taylor
Vice President, Capital Markets and Communications
1-403-817-9104
[email protected]
