CALGARY, ALBERTA–(Marketwired – Feb. 14, 2017) – ∩╗┐Spartan Energy Corp. (“Spartan” or the “Company”) (TSX:SPE) is pleased to provide a summary of our 2016 year-end reserves and an 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, 2016. All financial information presented in this press release is based on estimates and is unaudited.
2016 presented a unique opportunity for acquisitions in southeast Saskatchewan as the prolonged period of low crude oil prices resulted in a number of high quality assets becoming available. Spartan was able to use our attractive cost of capital and balance sheet flexibility to take advantage of this opportunity, as we completed five accretive acquisitions within our core southeast Saskatchewan operating area (the “Acquisitions”). The Acquisitions more than doubled the size of the Company, adding almost 11,000 boe/d of production, 43.3 MMboe of total proved (“1P”) reserves and 63.3 MMboe of proved plus probable (“2P”) reserves.
In addition to creating value through the Acquisitions, Spartan executed on a highly successful organic capital program in 2016. We continued to demonstrate cost savings throughout the year, and our total 2016 development capital (excluding land and capitalized G&A) of $59.6 million represented only 78% of estimated 2016 cash flow. Our development capital spending, including changes in future development capital but excluding capital associated with the Acquisitions, delivered 1P reserve additions of 5.9 MMboe and 2P reserve additions of 8.1 MMboe. Based on our estimated 2016 operating netback of $20.45 per boe, this results in a 1P recycle ratio of 1.3 times and 2P recycle ratio of 1.6 times.
The combination of accretive acquisitions and a successful drilling program allowed Spartan to add significant shareholder value in 2016 in the face of a challenging commodity price environment. Estimated 2016 average production of 11,759 boe/d represents 13% growth per debt adjusted share over 2015. Reserve growth per debt adjusted share was 55% for proved developed producing (“PDP”) reserves, 45% for 1P reserves and 32% for 2P reserves.
2016 RESERVES HIGHLIGHTS
- PDP Reserves
- Increased by 303% (55% per debt adjusted share) to 44.3 MMboe.
- The increase to PDP reserves replaced 2016 production by 790%.(1)
- PDP reserve life index is 5.8 years based on forecast 2017 production of 21,080 boe/d.(2)
- PDP reserves comprise 41% of 2P reserves and 64% of 1P reserves, up from 35% and 60%, respectively, in 2016.
- 1P Reserves
- Increased by 284% (45% per debt adjusted share) to 69.2 MMboe.
- Exclusive of acquisitions our capital program added 5.9 MMboe of 1P reserves, replacing 2016 production by 136%.(1)
- 1P reserves comprise 63% of 2P reserves, up from 58% in 2015.
- 1P reserve life index is 9.0 years based on forecast 2017 production of 21,080 boe/d.(2)
- 2P Reserves
- Increased by 260% (32% per debt adjusted share) to 109.1 MMboe.
- Exclusive of acquisitions our capital program added 8.1 MMboe of 2P reserves, replacing 2016 production by 187%.(1)
- 2P reserve life index is 14.2 years based on forecast 2017 production of 21,080 boe/d.(1)
- Finding and Development (“F&D”) Costs(3)
- F&D costs (including changes in FDC) were $15.83 per boe (1P) and $12.69 per boe (2P), representing a 1P recycle ratio of 1.3 times and 2P recycle ratio of 1.6 times based on Spartan’s estimated 2016 operating netback of $20.45 per boe.
- Finding, Development and Acquisition (“FD&A”) Costs(1)
- FD&A costs (including changes in FDC) were $24.18 per boe (1P) and $18.89 per boe (2P). The majority of reserve additions associated with the Acquisitions were completed pursuant to the acquisition of certain oil and gas assets from ARC Resources Ltd. on December 8, 2016. Using Spartan’s estimated fourth quarter operating netback of $25.31 per boe, the 1P recycle ratio was 1.0 times and 2P recycle ratio was 1.3 times.
- Spartan’s December 31, 2016 2P NPV 10% (before tax) net asset value, based on Sproule’s forecast pricing as at January 1, 2017, is $3.17 per share, up from $2.79 per share at year-end 2015.
- Approximately 62% of Spartan’s 1,424 net locations in southeast Saskatchewan remain unbooked.
Notes: | |
(1) | Production replacement ratio is calculated as increase to reserves divided by estimated 2016 average production of 11,759 boe/d. For 1P and 2P reserves, the increase to reserves is exclusive of reserves associated with the Acquisitions. See “Oil and Gas Advisories – Oil & Gas Metrics”. |
(2) | Reserve life index is calculated as total reserves divided by forecast 2017 average production. See “Oil and Gas Advisories – Oil & Gas Metrics”. |
(3) | See below under “2016 Finding and Development Costs and Recycle Ratios” for further detail on methodology for calculating these metrics. |
(4) | Financial information is based on the Company’s preliminary 2016 unaudited financial statements and is therefore subject to audit. |
2016 YEAR-END RESERVES SUMMARY
The summary below sets forth Spartan’s gross reserves as at December 31, 2016, 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, 2016 (1), (2), (3), (4)
Oil | Conventional Natural Gas |
Natural Gas Liquids |
Barrels of Oil Equivalent |
||
Gross | Gross | Gross | Gross | ||
(Mbbl) | (MMcf) | (Mbbl) | (Mboe) | ||
Proved | |||||
Developed Producing | 40,307.3 | 15,551 | 1,411.6 | 44,310.8 | |
Developed Non-Producing | 706.6 | 986 | 77.3 | 948.3 | |
Undeveloped | 18,596.9 | 22,595 | 1,586.6 | 23,949.3 | |
Total Proved | 59,610.8 | 39,132 | 3,075.5 | 69,208.4 | |
Probable | 34,965.4 | 19,980 | 1,624.4 | 39,919.7 | |
Total Proved plus Probable | 94,576.2 | 59,112 | 4,699.9 | 109,128.2 |
Summary of Net Present Values of Future Net Revenue as of December 31, 2016 (1), (2), (3), (4)
Net Present Value Before Income Taxes Discounted at (% per Year) (M$) |
||||||
0% | 5% | 10% | 15% | 20% | ||
Proved | ||||||
Developed Producing | 1,323,361 | 1,014,821 | 825,559 | 698,818 | 608,303 | |
Developed Non-Producing | 23,295 | 17,927 | 14,234 | 11,618 | 9,704 | |
Undeveloped | 575,462 | 420,267 | 314,171 | 239,706 | 185,763 | |
Total Proved | 1,922,118 | 1,453,015 | 1,153,964 | 950,142 | 803,770 | |
Probable | 1,507,858 | 965,866 | 682,770 | 514,999 | 406,620 | |
Total Proved plus Probable | 3,429,976 | 2,418,881 | 1,836,734 | 1,465,141 | 1,210,391 |
Notes: | |
(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, 2016 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 |
2017 | 118,978.9 | 127,113.6 |
2018 | 163,176.3 | 167,438.6 |
2019 | 139,478.5 | 180,090.3 |
2020 | 7,700.4 | 107,482.7 |
2021 | 6,754.5 | 105,913.8 |
Thereafter | 37,637.8 | 78,340.9 |
Total Undiscounted | 473,726.4 | 766,379.9 |
Total Discounted at 10% | 391,932.5 | 585,705.1 |
The future development costs are estimates of capital expenditures required in the future for Spartan to convert proved undeveloped reserves and probable reserves to proved developed producing reserves. The undiscounted future development costs are $473.7 million for proved reserves and $766.4 million for proved plus probable reserves (in each case based on forecast prices and costs).
Summary of Pricing and Inflation Rate Assumptions – Forecast Prices and Costs
The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by Sproule as at December 31, 2016 were as follows:
Year | WTI Cushing Oklahoma 40ºAPI ($US/bbl) |
Canadian Light Sweet 40ºAPI ($Cdn/ bbl) |
Cromer LSB 35º API ($Cdn/ bbl) |
Natural Gas AECO ($Cdn/ MMBTu) |
Propane at Edmonton ($Cdn/ bbl) |
Butane at Edmonton ($Cdn/ bbl) |
Inflation Rate %/year |
Exchange Rate ($US/ $CDN) |
2017 | 55.00 | 65.58 | 64.58 | 3.44 | 22.74 | 47.60 | 0 | 0.78 |
2018 | 65.00 | 74.51 | 73.51 | 3.27 | 28.04 | 55.49 | 2.0 | 0.82 |
2019 | 70.00 | 78.24 | 77.24 | 3.22 | 30.64 | 57.65 | 2.0 | 0.85 |
2020 | 71.40 | 80.64 | 79.64 | 3.91 | 32.27 | 58.80 | 2.0 | 0.85 |
2021 | 72.83 | 82.25 | 81.25 | 4.00 | 33.95 | 59.98 | 2.0 | 0.85 |
2022 | 74.28 | 83.90 | 82.90 | 4.10 | 35.68 | 61.18 | 2.0 | 0.85 |
2023 | 75.77 | 85.58 | 84.58 | 4.19 | 37.46 | 62.40 | 2.0 | 0.85 |
2024 | 77.29 | 87.29 | 86.29 | 4.29 | 39.30 | 63.65 | 2.0 | 0.85 |
2025 | 78.83 | 89.03 | 88.03 | 4.40 | 41.19 | 64.92 | 2.0 | 0.85 |
2026 | 80.41 | 90.81 | 89.81 | 4.50 | 43.13 | 66.22 | 2.0 | 0.85 |
2027 | 82.02 | 92.63 | 91.63 | 4.61 | 45.14 | 67.54 | 2.0 | 0.85 |
Thereafter | Escalation Rate of 2.0% |
2016 FINDING AND DEVELOPMENT COSTS AND RECYCLE RATIOS
F&D Costs
F&D Costs (M$) | ||
Proved Reserves |
Proved Plus Probable Reserves |
|
Exploration and Development Capital | 49,551 | 49,551 |
Total change in FDC | 43,101 | 52,835 |
Total F&D capital including change in FDC | 92,652 | 102,386 |
Total Reserve additions, including revisions (Mboe) | 5,851 | 8,067 |
F&D costs, including FDC ($/boe) | 15.83 | 12.69 |
Notes: | |
(1) | Financial information is based on the Company’s preliminary 2016 unaudited financial statements and is therefore subject to audit. |
(2) | The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. |
(3) | Exploration and Development Capital excludes (a) acquisition costs; (b) exploration and development capital incurred in respect of acquired assets where associated reserve additions are attributed to acquisitions; (c) land expenditures; and (d) capitalized general and administration costs. |
FD&A Costs
FD&A Costs (M$) | ||
Proved Reserves |
Proved Plus Probable Reserves |
|
Exploration and Development Capital | 59,609 | 59,609 |
Acquisition Cost | 864,120 | 864,120 |
Total change in FDC | 263,830 | 424,721 |
Total FD&A capital including change in FDC | 1,187,559 | 1,348,450 |
Total Reserve additions, including revisions (Mboe) | 49,119 | 71,396 |
FD&A costs, including FDC ($/boe) | 24.18 | 18.89 |
Notes: | |
(1) | Financial information is based on the Company’s preliminary 2016 unaudited financial statements and is therefore subject to audit. |
(2) | The aggregate of the exploration, development and acquisition 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, development and acquisition costs related to reserves additions for that year. |
(3) | Capital expenditures exclude land expenditures and capitalized general and administration costs. |
(4) | Recycle ratio is calculated as operating netback divided by F&D per boe. Operating netback is calculated as revenue minus royalties and production expenses. Spartan’s unaudited operating netback for 2016 was $20.45 per boe. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. |
NET ASSET VALUE
Based on Sproule December 31, 2016 forecast pricing, Spartan’s net asset value calculation is as follows:
NAV ($M except per share amounts) | |||
2P Reserves NPV10 BT | $ | 1,836,734 | |
Undeveloped Land and Seismic Value(1) | $ | 122,610 | |
Estimated Net Debt (unaudited) (2) | $ | (214,609 | ) |
Proceeds from Dilutive Securities | $ | 54,843 | |
Total Net Assets | $ | 1,799,579 | |
Fully Diluted shares outstanding (000’s) | 568,573 | ||
Estimated NAV per Fully Diluted Share | $ | 3.17 | |
Notes: | |
(1) | Internally evaluated. |
(2) | Excluding finance lease obligations. |
OPERATIONAL UPDATE
Spartan’s southeast Saskatchewan focused asset base has continued to deliver superior operational results. In 2016, we drilled and brought on production 39.9 net open-hole wells and 10.8 net frac Midale wells. We also completed and brought on production 5.9 net previously drilled Viking wells, drilled 6.1 net strat test wells and re-entered or re-completed 3.0 net existing wells. We continued to lower our drilling costs throughout the year, while our wells again outperformed internal type curves. The success of our drilling program, in combination with our accretive acquisitions, allowed Spartan to deliver 13% production per debt adjusted share growth year over year despite spending less than cash flow.
We have been active in the field to start 2017, with three rigs operating on our southeast Saskatchewan assets and an additional rig drilling our 14 well Viking program in west central Saskatchewan. To date we have drilled 19.3 net wells, including 8.2 net open-hole wells, 3.1 net frac Midale wells, and 8.0 net Viking wells and one net vertical strat well. Conditions remain favourable in the field and we anticipate our first quarter program will be completed as budgeted prior to the onset of spring break-up.