CALGARY, ALBERTA–(Marketwired – May 13, 2016) – Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or the “Company”) is pleased to announce the closing of the previously announced light oil joint venture with Murphy Oil Company Ltd. (“Murphy”) in the Kaybob Area (“Murphy Transaction”). The transaction right sizes the Company’s capital risk profile and puts it in a strong position to align its capital structure and operating plans over the mid-term.
“This transaction is pivotal to the future long-term health and success of Athabasca,” said Rob Broen, President and CEO of Athabasca. “The partnership with Murphy advances our strategic goal of transitioning the Duvernay to commercial development and enabling scalable Montney growth while giving Athabasca a more appropriate capital risk profile. The fact is, developing the Duvernay requires significant capital investment beyond our own balance sheet capability. This partnership gives shareholders a funded growth profile and material long term upside while bolstering our financial position.”
Athabasca sold a 70% interest in its Greater Kaybob area assets and a 30% interest in its Greater Placid area assets for gross proceeds of $486 million, including closing adjustments. Athabasca received cash consideration of $267 million and an additional $219 million capital carry commitment whereby Murphy will fund 75% of Athabasca’s share of Duvernay development capital up to a maximum five year period. Murphy will assume operatorship of the Greater Kaybob area assets and Athabasca will retain operatorship of the Greater Placid area assets. Joint development agreements are in place that are intended to preserve the value of the Company’s interests, ensure strategic alignment on Duvernay growth and provide flexibility to accelerate activity in Greater Placid where the Company has established a core operated position.
Strategic Update
Over the past two years and under its new leadership Athabasca has taken steps forward to reduce capital spending, improve its cost structure and grow a track record of strong operational results. Now in its next step, this joint venture transforms Athabasca as it establishes a well-funded growth strategy in Light Oil that is complementary to the Company’s overall corporate strategy. Athabasca’s go forward strategy now includes the following highlights:
- Defined and material Light Oil growth
- Scalable Montney position – Building on a successful five well appraisal campaign, Athabasca will operate a multi-year development plan under the Placid joint venture, with a current inventory of approximately 165 gross wells and a 70% working interest. This development is expected to have top quartile returns and is economic in today’s commodity price environment. The asset has gross production potential in excess of 8,000 boe/d (5,500 boe/d net) in 2017 and in excess of 17,000 boe/d (12,000 boe/d net) at the end of five years.
- Funded Duvernay development – The development plan under the Kaybob joint venture is structured to result in approximately $1 billion of gross investment over the first four to five years, which is expected to drive gross production potential to approximately 30,000 boe/d (9,000 boe/d net) at the end of five years. Athabasca’s net capital exposure under this development plan is approximately $75 million, following which the assets are expected to be self-funding. Athabasca retains a 30% working interest in over 200,000 gross acres and up to 1,500 gross drilling locations.
- Thermal Oil leverage to a pricing recovery
- Cash flow torque at Hangingstone – Athabasca’s Phase 1 SAGD facility at Hangingstone has recently been producing at 9,000 bbl/d and is expected to reach nameplate of 12,000 bbl/d by the end of 2016. This property requires minimal capital investment over the initial 5 – 7 years to hold production levels flat. The asset has an operating breakeven price between US$40 – 45/bbl WTI, with the potential to generate significant operating income for the Company at higher commodity prices.
- Future low risk expansion options – Hangingstone has options for phased brownfield expansions up to 80,000 bbl/d. Future phases are expected to have strong capital efficiencies by utilizing existing regional infrastructure. The Company has approximately 5.9 billion barrels (unrisked best estimate contingent resource) of future resource potential in its other thermal assets.
- Financial sustainability with a funded growth profile
- Strong balance sheet – Athabasca currently has approximately $880 million of liquidity and a net cash position of approximately $60 million. Liquidity is further bolstered by the $219 million Duvernay capital carry commitment.
- Favorable outlook – The Company remains committed to its 2016 priorities of reducing total leverage by $300 to $400 million and extending its 2017 debt maturities, steps which will further enhance Athabasca’s financial flexibility and sustainability. The Company is positioned to become free cash flow positive within the next 3 – 5 years.
Light Oil Development
Athabasca has focused the last three years on appraisal and development of its significant Duvernay and Montney land position in Greater Kaybob and Placid. The Company has drilled 26 Duvernay wells at Greater Kaybob and five Montney wells at Placid and has established a core operated infrastructure position in an area that continues to be actively developed by large industry players. Athabasca has demonstrated its operating capability with strong well results and now has a land base that is set up for larger development in an improved commodity price environment.
Placid Montney Development Plans (Athabasca operated & 70% working interest)
In the Montney play at Placid, the Company has exposure to approximately 25,000 gross acres of prospective Montney land with two separately defined Montney intervals and an estimated inventory of over 165 Montney locations. The Company has established the Placid Montney as a core operated area following a successful five well appraisal program.
The Greater Placid joint development plan with Murphy will build on this success which has delineated a liquids rich sweet spot. The initial development plan has flexibility to accelerate activity and the asset has gross production potential in excess of 8,000 boe/d (5,000 boe/d net) in 2017 and in excess of 17,000 boe/d (12,000 boe/d net) at the end of five years. For context, a single rig has the capability to drill 10 to 12 wells per year driving capital expenditures between $75 – $100 million (gross).
Greater Kaybob Duvernay Development Plans (Murphy operated, Athabasca 30% working interest)
The Murphy Transaction materially progresses Athabasca’s strategic goal of transitioning the Duvernay shale play into full development over the mid-term. It is anticipated to provide shareholders with a defined funded growth profile that will leverage off Murphy’s extensive experience in the Eagle Ford oil window. As a result of the transaction, Athabasca believes that it has now positioned itself with a capital risk profile appropriate to its size while retaining material upside in the Duvernay. The Duvernay capital carry will significantly reduce the Company’s initial capital outlay following which the assets are expected to become self-funding.
The joint development plan has been designed to assess commerciality across the land base, satisfy the majority of the land tenure requirements by the end of the intermediate term and advance the asset to the self-funding stage.
The development plan contemplates approximately $1 billion of gross investment over the first four to five years with gross production potential up to 30,000 boe/d (60% liquids, 9,000 boe/d net). Athabasca’s net capital exposure is approximately $75 million on this first $1 billion of gross investment and the Company will retain a 30% working interest in over 200,000 gross Duvernay acres. The joint development agreement provides for flexibility to adapt annual capital expenditures to prevailing commodity prices and drilling results. The agreement also provides that a minimum annual capital carry amount will be paid by Murphy, and if the annual minimum is not met through operations under the development plan, Murphy will pay the difference to Athabasca.
The development plan includes drilling approximately 100 gross Duvernay wells over the first four years, of which ~70% are planned to target the volatile oil window (extending across Simonette, Kaybob West North, Kaybob East and Two Creeks). The joint venture will leverage both partners’ extensive shale play expertise, specifically Murphy’s track record for organic growth in the Eagle Ford oil window where the company has grown gross production to in excess of 60,000 boe/d by drilling 700+ wells.
Additional details on the proposed Montney and Duvernay development plans are outlined in the latest corporate presentation on slides 9 and 14 available at www.atha.com.
Financial Position and 2016 Outlook
The Company’s 2016 capital budget is currently unchanged and at this time no additional Light Oil capital has been approved for the second half of 2016. Athabasca maintains operational readiness to accelerate development in both the Montney and Duvernay and the Company anticipates providing updated capital plans mid-summer.
Athabasca currently has approximately $880 million of liquidity and a net cash position of approximately $60 million providing a multi-year funding horizon. Liquidity is further bolstered by the $219 million Duvernay capital carry commitment. The Company remains focused on its culture of strong capital discipline demonstrated over the past two years.
Maintaining a strong balance sheet also continues to be a key priority and the Company is progressing alternatives to enhance its capital structure. Athabasca remains committed to reducing total leverage by $300 to $400 million during 2016 and to ensure necessary debt tenure and liquidity are in place to support the Company’s strategic business objectives.
Thermal Oil – Hangingstone Update
Hangingstone operations were shut down on May 5, 2016 due the regional Fort McMurray wildfires. There is currently no damage to the facility, field pipelines or well sites. The fire front is approximately five kilometers north of the assets and at this time, it has not advanced closer. The fire near Athabasca’s facilities is actively being contained. Timing for a complete restart of operations is contingent on the continued containment of the regional fires and on ensuring safe operating conditions. Prior to the shut down, production reached approximately 9,000 bbl/d. Operating Income break-evens are US$40 – 45/bbl WTI and the asset has the potential to add significant cash flow to the Company in an improved price environment.
| 2016 Capital Budget(1)($ million) | Full Year | ||||
| Gross | Net | ||||
| LIGHT OIL | |||||
| Greater Kaybob (Duvernay)(2) | $ | 39 | $ | 13 | |
| Greater Placid (Montney)(3) | 33 | 30 | |||
| Total Light Oil | $ | 71 | $ | 42 | |
| THERMAL OIL | |||||
| Hangingstone Maintenance | $ | 7 | |||
| Other Thermal | 4 | ||||
| Total Thermal | $ | 11 | |||
| Capitalized G&A | $ | 8 | |||
| TOTAL CAPITAL SPENDING | $ | 61 | |||
| (1) | Figures may not add up due to rounding. |
| (2) | Greater Kaybob net capital reflects Athabasca’s 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) | |||
| Production (boe/d) | 4,500 – 5,000 | ||
| Liquids Weighting (%) | 55 | % | |
| Operating Income(1) ($MM) | ~$26 | ||
| Operating Netback ($/boe) | ~$14.75 | ||
| THERMAL OIL | |||
| Bitumen Production (bbl/d) | 9,000 – 10,000 | ||
| Operating Income(1) ($MM) | ~($41 | ) | |
| CORPORATE | |||
| Production (boe/d) | 13,500 – 15,000 (~85% liquids | ) | |
| Funds Flow from Operations(1) ($MM) | ~($97 | ) | |
| Net Debt(2) ($MM) | ~$20 | ||
| Cash & Equivalents(2) ($MM) | ~$765 | ||
| COMMODITY ASSUMPTIONS (strip pricing as at April 25) | |||
| WTI (US$/bbl) | $41.49 | ||
| Edmonton Par (C$/bbl) | $49.10 | ||
| Western Canadian Select (C$/bbl) | $34.90 | ||
| AECO Gas (C$/mcf) | $1.70 | ||
| FX (US$/C$) | 0.773 | ||
| (1) | Operating Income and Funds Flow from Operations estimates reflect the mid-point of production guidance. Thermal Operating Income reflects the production ramp-up to design capacity by the end of 2016. |
| (2) | Net debt and cash equivalents forecasts assume the current capital structure and exclude debt repayment target of $300 – $400 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.
Reader Advisory:
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe”, “predict”, “pursue”, “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, including information pertaining to the following: the benefits expected to be realized by the Company from the Murphy Transaction, including the impact on the Company’s financial position and balance sheet strength, the preservation of the Company’s value in the Great Kaybob and Greater Placid area assets, the flexibility to accelerate activity in Placid and the Company’s ability to leverage from Murphy’s extensive experience in the Eagle Ford oil window; the Company’s expectation that the Murphy Transaction will result in a well-funded growth strategy and will progress Athabasca’s goal of transitioning the Duvernay shale play into full development over the mid-term; the estimated gross production potential and production upside of the Placid and Kaybob area assets; the Company’s forecasted liquidity and net cash position upon closing of the Murphy Transaction; the estimated capital to be spend by Murphy and Athabasca under the Kaybob joint venture over the next four to five years; the expected potential of the Duvernay volatile oil window; the growth potential of and the economic returns expected to be realized from, the Company’s Montney lands in the Placid area including the expectation that they will have top quartile returns; the improvements in Duvernay well drilling and completion costs expected to be realized by the Company, including from employing pad drilling; the timing of completion and commissioning operations in the Company’s Light Oil division; 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; Athabasca’s plans to retire a portion of its debt in 2016 and extend its 2017 debt maturities; the Company’s ability to enhance its financial flexibility and sustainability; the Company’s expectation to be free cash flow positive within the next 3-5 years; the timing of the ramp-up of production and of achieving plateau production from Hangingstone Project 1; the Company’s expectation that Hangingstone Project 1 will have a flat production profile for its initial 5 to 7 years of production after achieving nameplate production (12,000 bbl/d); the potential of the Hangingstone Project 1 to generate significant operating income; the expectation that future phases at Hangingstone will have strong capital efficiencies by utilizing existing regional infrastructure; the Company’s estimated future commitments; the Company’s business and financing strategies and plans; expectations regarding the Company’s 2016 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; the impact that the Murphy Transaction will have on the Company, including on the Company’s financial condition and results of operations; the Company’s ability to meet its re-financing objectives; the Company’s capital discipline; the Company’s ability to accelerate development when prices recover; the cycle times of the Montney multi-well pad operations; the drill capacity of a single rig; the flexibility of the Kaybob joint venture to adapt annual capital expenditures to prevailing commodity prices and drilling results; 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: risks associated with regional forest fires and other events of force majeure affecting Athabasca’s operations, 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; compliance with greenhouse gas regulations; changes to royalty regimes, environmental risks and hazards; alternatives to and changing demand for petroleum products; failure to meet the conditions precedent to closing of the Murphy Transaction; dependence on Murphy as the Company’s joint venture participant in the Company’s Duvernay and Montney assets; 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; 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 Murphy Transaction, and the possible consequences thereof; the potential for adverse consequences in the event that the Company defaults under certain of the agreements in respect of the Murphy 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; the potential for management estimates and assumptions to be inaccurate; 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; senior secured notes and term loans; 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 AIF available on SEDAR at www.sedar.com. 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.
Drilling Locations: the 1,500 Duvernay drilling locations referenced in this release includes: 5 proved undeveloped locations, 33 probable undeveloped locations, with the balance being unbooked locations. The 165+ Montney inventory referenced in this 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.
Matthew Taylor
Vice President, Capital Markets and Communications
1-403-817-9104
[email protected]
www.atha.com
