CALGARY, Alberta, Feb. 21, 2018 (GLOBE NEWSWIRE) — Spartan Energy Corp. (“Spartan” or the “Company”) (TSX:SPE) is pleased to provide a summary of our 2017 year-end reserves and a 2017 operational update. Reserve numbers presented herein were derived from an independent reserves report (the “Sproule Report”) prepared by Sproule Associates Ltd. (“Sproule”) effective December 31, 2017. All 2017 financial information presented in this press release is based on management’s preliminary estimates and is unaudited and subject to change.
2017 OPERATING HIGHLIGHTS
In 2016, Spartan’s business plan was to capitalize on market conditions to enhance our asset base through accretive acquisitions. We were able to take advantage of the opportunity, completing five acquisitions to increase production by almost 11,000 boe/d while also bolstering our inventory of economic drilling locations, improving the quality of our reserve base and lowering our corporate decline.
Entering 2017, our focus was on integrating our acquisitions, delivering top tier growth through our organic drilling program and reinvesting excess funds flow to enhance shareholder value. Our 2017 results exceeded expectations, clearly demonstrating the growth and free cash flow generating ability of our light oil asset base:
- Average 2017 production of approximately 22,200 boe/d represented production per share growth of 17% over 2016.
- We delivered adjusted funds flow from operations in the fourth quarter of $65 million, representing a per share increase of 61% over the third quarter of 2016 and 48% over the fourth quarter of 2016.
- Annual adjusted funds flow from operations of $201 million in 2017 represented a per share increase of 61% over 2016. The majority of this funds flow growth resulted from our operating success, as Canadian dollar WTI price increased only 16% during the same period.
- Our 2017 development capital (total capital less land, seismic, waterflood capital and acquisitions) of $141 million represented only 70% of adjusted funds flow from operations.
- In a WTI price environment that was significantly lower than current prices (2017 US$ WTI averaged less than $51), Spartan generated excess funds flow (adjusted funds flow from operations less development capital) of $60 million.
- We executed our most efficient drilling program to date, further reducing drilling costs while outperforming our internal type curve for both open-hole and frac Midale wells. This outperformance resulted in Spartan upwardly revising our production guidance twice through 2017 while reducing our capital spending.
- We successfully invested our excess funds flow in projects focused on long term value creation:
- We completed four strategic tuck-in acquisitions for total cash consideration of approximately $27 million. Through these acquisitions we brought our interest in the Oungre Ratcliffe unit to 100%, allowing for control and accelerated development of our waterflood project in the unit. In addition, we added 45 net drilling locations in our core Winmore area, where we have proprietary seismic coverage and have consistently delivered well results far exceeding our internal type curve. The majority of the upside associated with these acquisitions remains unbooked and provides opportunity for future production and reserves growth.
- We commenced activity on our waterflood projects in the second half of the year, spending approximately $3 million. Waterflood initiatives have continued into 2018 and we have budgeted for $17 million in waterflood spending in 2018. Due to the early stage of our projects we currently have minimal waterflood bookings in our reserve report. Spartan believes that our waterflood assets have potential to deliver significant reserves growth in future years with finding and development costs as low as $5.00 per boe.
- We invested approximately $9 million in a land and seismic acquisition program designed to complement our asset base and add to our future drilling inventory.
- Our remaining excess funds flow was applied to reduce our year-end net debt (excluding finance lease obligations) to approximately $199 million from $215 million in 2016, representing a debt to cash flow ratio of 1.0 times (0.8 times based on our annualized fourth quarter adjusted funds flow from operations).
2017 RESERVES HIGHLIGHTS
- Our capital program added approximately 9.1 million barrels of oil equivalent (“MMboe”) of proved developed producing (“PDP”) reserves, 11.9 MMboe of proved (1P) reserves and 12.5 MMboe of proved plus probable (“2P”) reserves, delivering reserves growth of 2% (PDP), 5% (1P) and 4% (2P).
- The increase in reserves replaced production by 12% on a PDP basis, 46% on a 1P basis and 54% on a 2P basis.(1)
- Our asset base remains conservatively booked providing significant opportunity for future reserves growth:
- Only 598 of our 1,575 net internally identified drilling locations in southeast Saskatchewan are booked by Sproule, leaving 61% of our locations unbooked.
- Undiscounted 2P FDC of approximately $810.7 million represents approximately 4.1 times our 2017 adjusted funds flow from operations.
- Finding and development (“F&D”) costs (including changes in FDC) were $19.75 per boe (1P) and $17.10 per boe (2P), representing a 1P recycle ratio of 1.4 times and 2P recycle ratio of 1.6 times based on Spartan’s estimated 2017 operating netback of $27.01 per boe. Using our estimated fourth quarter operating netback of $32.95 per boe, our 2P recycle ratio increases to 1.9 times.(2)
- Our 2P reserves life index is 14.0 years based on 2017 average production of 22,200 boe/d.(3)
- Spartan’s December 31, 2017 2P NPV 10% (before tax) net asset value, based on Sproule’s forecast pricing as at January 1, 2017, is $10.15 per share, up from $9.51 at year-end 2016.
(1) Production replacement ratio is calculated as increase to reserves divided by estimated 2017 average production of 22,200 boe/d. See “Oil and Gas Advisories – Oil & Gas Metrics”.
(2) See below under “2017 Finding and Development Costs” for further detail on methodology for calculating these metrics.
(3) Reserve life index is calculated as total reserves divided by 2017 average production. See “Oil and Gas Advisories – Oil & Gas Metrics”.
(4) Financial information is based on the Company’s preliminary 2017 unaudited financial statements and is therefore subject to change.
2017 YEAR-END RESERVES SUMMARY
The summary below sets forth Spartan’s gross reserves as at December 31, 2017, as evaluated in the Sproule Report. The figures in the following tables have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and the reserve definitions contained in NI 51-101.
Summary of Gross Oil and Gas Reserves as of December 31, 2017(1), (2), (3), (4)
|Barrels of Oil
|Total Proved plus Probable||99,392.9||52,514||5,340.0||113,485.2|
Summary of Net Present Values of Future Net Revenue as of December 31, 2017 (1), (2), (3), (4)
|Net Present Value Before Income Taxes
Discounted at (% per Year) (M$)
|Total Proved plus Probable||3,741,223||2,589,715||1,956,912||1,557,878||1,284,557|
(1) The tables summarize the data contained in the Sproule Report and as a result may contain slightly different numbers due to rounding.
(2) Gross reserves means the total working interest (operating and non-operating) share of remaining recoverable reserves owned by Spartan before deductions of royalties payable to others and without including any royalty interests owned by Spartan.
(3) Based on Sproule’s December 31, 2017 escalated price forecast. See “Summary of Pricing and Inflation Rate Assumptions”.
(4) The net present value of future net revenue attributable to the Company’s reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Company’s reserves estimated by Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
Future Development Costs
The following table sets forth development costs deducted in the estimation of Spartan’s future net revenue attributable to the reserve categories noted below:
|Forecast Prices and Costs (M$)|
|Year||Proved Reserves||Proved Plus Probable Reserves|
|Total Discounted at 10%||436,365.0||620,216.8|
The future development costs are estimates of capital expenditures required in the future for Spartan to convert proved undeveloped reserves and probable undeveloped reserves to proved developed producing reserves. The undiscounted future development costs are $543.2 million for proved reserves and $810.7 million for proved plus probable reserves (in each case based on forecast prices and costs).
Summary of Pricing and Inflation Rate Assumptions – Forecast Prices and Costs
The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by Sproule as at December 31, 2017 were as follows:
|Year||WTI Cushing Oklahoma
|Canadian Light Sweet
|Cromer LSB 35⁰ API
|Natural Gas AECO
|Propane at Edmonton
|Butane at Edmonton
|Thereafter||Escalation Rate of 2.0%|
FINDING AND DEVELOPMENT COSTS
|F&D Costs (M$)|
|Proved Reserves||Proved Plus Probable Reserves|
|Exploration and Development Capital||140,193||140,193|
|Total change in FDC||64,819||34,005|
|Total F&D capital including change in FDC||205,012||174,198|
|Total Reserve additions, including revisions (Mboe)||10,378||10,186|
|F&D costs, including FDC ($/boe)||19.75||17.10|
(1) Financial information is based on the Company’s preliminary 2017 unaudited financial statements and is therefore subject to change.
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
(3) Exploration and Development Capital excludes (a) acquisition costs; (b) exploration and development capital incurred in respect of acquired assets where associated reserve additions are attributed to acquisitions; (c) land expenditures; and (d) capitalized general and administration costs.
NET ASSET VALUE
Based on Sproule December 31, 2017 forecast pricing, Spartan’s net asset value calculation is as follows:
|NAV ($M except per share amounts)|
|2P Reserves NPV10 BT||$1,956,912|
|Undeveloped Land and Seismic Value(1)||$123,580|
|Estimated Net Debt (unaudited) (2)||($199,204||)|
|Proceeds from Dilutive Securities||$24,318|
|Total Net Assets||$1,905,606|
|Fully Diluted shares outstanding (000’s)||187,806|
|Estimated NAV per Fully Diluted Share||$10.15|
(1) Internally evaluated.
(2) Excluding finance lease obligations.
(3) Financial information is based on the Company’s preliminary 2017 unaudited financial statements and is therefore subject to change.
Spartan’s asset base is characterized by a light oil, low decline production base with an extensive drilling inventory of low risk, low cost, highly economic open-hole and frac Midale drilling locations in southeast Saskatchewan. The strength of our assets allowed us to deliver top tier production growth in 2017, while limiting our development capital spending to 70% of our adjusted funds flow from operations and investing in projects that create long term value for our shareholders. We remain well positioned to continue this business plan in 2018, with our $183 development capital budget forecast to generate 11% exit production growth and excess funds flow of $84 million (based on a US $60 WTI oil price). We will seek to use our free cash flow profile to maximize long term returns for our shareholders through the development of our waterflood projects and completion of strategic tuck-in acquisitions. Additionally, depending on market conditions, we intend to further increase our per share net asset value through accretive share buybacks under our normal course issuer bid.