Painted Pony Announces 4.9 TCFE of Proved Plus Probable Reserves, 102% Increase in Proved Developed Producing Reserves, 2016 Year End Financial and Operating Results, and Operational Update
CALGARY, Feb. 27, 2017 /CNW/ - Painted Pony Petroleum Ltd. ("Painted Pony" or the "Corporation") (TSX: PPY) is pleased to announce strong finding and development ("F&D") costs, the third consecutive year of per Mcfe cash cost reductions, a 95% increase to funds flow from operations for 2016, further decreases in per-well capital expenses, and record-high production volumes during the fourth quarter of 2016.
2016 Reserve Highlights:
- Increased Total Proved ("1P") reserves by 31% to 2.7 Tcfe at year end 2016 from 2.0 Tcfe at year end 2015;
- Increased Proved Developed Producing ("PDP") reserves by 102% to 484 Bcfe
(80.7 MMboe) from 240 Bcfe (40.0 MMboe); - Increased Proved Plus Probable ("2P") reserves 7% to more than 4.9 Tcfe at year-end 2016 from 4.6 Tcfe at year-end 2015;
- Generated a finding, development and acquisition ("FD&A") PDP recycle ratio of 2.0 times and a 1P recycle ratio of 2.6 times, inclusive of changes in future development capital ("FDC");
- Reduced 2P FDC by approximately $300 million or 9% to $2.9 billion at year-end 2016 from $3.2 billion at year-end 2015 as a result of improved well cost structure;
- Realized reductions in 2P FDC exceeded capital spent in 2016, which resulted in negative 2P FD&A and 2P F&D costs;
- Increased PDP before tax net present values at December 31, 2016 discounted at 10% ("NPV10") by 119% to $7.04/share in 2016 from $3.23/share in 2015;
- Replaced 579% of 2016 production volumes through PDP reserve additions of 295 Bcfe (49.2 MMboe);
- Achieved a 1P NPV10 value/share increase of 65% to $22.92/share at year-end 2016 from $13.92/share at year-end 2015;
2016 Fourth Quarter and Full Year Production Highlights
- Increased fourth quarter 2016 average daily production volumes by 144% to 220.2 MMcfe/d (36,695 boe/d) over fourth quarter 2015 average daily production volumes of 90.3 Mcfe/d (15,043 boe/d);
- Averaged annual daily production volumes of 139.2 MMcfe/d (23,204 boe/d) during 2016 and a 49% increase over 2015 annual average daily production of 93.6 MMcfe/d (15,604 boe/d);
- Natural gas liquids ("NGL") production volumes increased 416% to 3,177 bbls/d during the fourth quarter of 2016 compared to 616 bbls/d during the fourth quarter of 2015;
2016 Fourth Quarter and Full Year Financial Highlights
- Increased funds flow from operations during the fourth quarter of 2016 by a factor of 10 times to $26.5 million ($0.26/share) compared to $2.6 million ($0.03/ share) during the fourth quarter of 2015;
- Realized commodity price discount to AECO daily spot price was reduced to 6% during 2016 compared to a 22% discount to AECO daily spot price during 2015;
- Reduced annual cash operating costs (royalties, operating expenses and transportation costs) by $0.32/Mcfe (24%) to $1.04/Mcfe in 2016 from $1.36/Mcfe in 2015, and;
- Realized pre-tax income, of $8.0 million during the fourth quarter of 2016, before unrealized non-cash hedging losses.
Mr. Patrick Ward, President and CEO of Painted Pony, in commenting on these highlights said, "Painted Pony executed a capital plan in 2016 that delivered results for shareholders entirely consistent with our 5 year plan, most notably organic production growth per share of more than 150% exit 2016 over exit 2015. The significant production milestones achieved in 2016 combined with decreasing cash expenses, continued capital cost reductions, and robust full-cycle economics highlighted by a strong PDP recycle ratio of 2.0 times, positions Painted Pony as an industry leader in low-cost, full-cycle Montney development."
2017 Capital Budget and 2018 Development Plans
Painted Pony's 2017 capital budget and 5-year plan are reviewed regularly by the Corporation's executive and Board of Directors. Due to the recent decline in forward strip natural gas prices, Painted Pony is prudently reviewing its 2017 capital budget and 2018 development plans to ensure the Corporation maintains its current financial flexibility. Painted Pony has financially hedged approximately 65% of 2017 natural gas production volumes and, when combined with indexed physical contracts, is well positioned to withstand lower natural gas prices.
SUMMARY OF 2016 RESERVES AS PREPARED BY GLJ PETROLEUM CONSULTANTS
2016 Summary of Reserves
GLJ Petroleum Consultants Ltd. ("GLJ"), independent qualified reserves evaluators, prepared an evaluation of Painted Pony's properties effective December 31, 2016, which is contained in a report dated February 27, 2017.
2P
During 2016, Painted Pony increased 2P reserves by 7% to 4.9 Tcfe (823 MMboe). As a result, 2P reserves per share increased to 49.3 Mcfe/share (8.2 boe/share) at year-end 2016 from 46.1 Mcfe/share (7.7 boe/share) at year-end 2015. The estimated NPV10 of 2P reserves at December 31, 2016 increased by 28% to $3.8 billion over year-end 2015 of $2.9 billion. The Corporation's 2P reserve additions replaced 2016 average daily production of 139.2 MMcfe/d (23,204 boe/d) by 7.5 times.
1P
During 2016, Painted Pony increased 1P reserves by 31% to 2.7 Tcfe (442 MMboe). As a result, 1P reserves per share increased to 26.5 Mcfe/share (4.4 boe/share) at year-end 2016 from 20.2 Mcfe/share (3.4 boe/share) at year-end 2015. The estimated NPV10 of 1P reserves at December 31, 2016 increased by 65% to $2.3 billion over year-end 2015 of $1.4 billion. The Corporation's 1P reserve additions replaced 2016 average daily production of 139.2 MMcfe/d (23,204 boe/d) by 13.4 times.
PDP
During 2016, Painted Pony increased PDP reserves by 102% to 484 Bcfe (80.7 MMboe). As a result, PDP reserves per share increased to 4.8 Mcfe/share (0.8 boe/share) at year-end 2016 from 2.4 Mcfe/share (0.4 boe/share) at year-end 2015. The estimated NPV10 of PDP reserves at December 31, 2016 increased by 119% to $705 million ($7.04/share) over year-end 2015 of $323 million, ($3.23 /share). The Corporation's PDP reserve additions replaced 2016 average daily production of 139.2 MMcfe/d (23,204 boe/d) by 5.8 times.
Reserve Life Index
Painted Pony accelerated value in 2016 by reducing the 2P reserve life index ("RLI"), based on fourth quarter 2016 annualized production, to 61 years at the end of 2016 from 140 years at the end of 2015, and the 1P RLI to 33 years at the end of 2016 from 61 years at the end of 2015.
2016 FINDING AND DEVELOPMENT COSTS AND RECYCLE RATIOS
Painted Pony's reduced FDC led to a negative 2P F&D cost, resulting in an incalculable recycle ratio. In 2016, the Corporation generated an FD&A 1P recycle ratio of 2.6 times and 2.0 times on an FD&A PDP basis. This is calculated by dividing Painted Pony's average operating netback (incl. Finance Lease Expense) of $1.45/Mcfe, which is calculated using revenue plus realized hedging gains less royalties, operating expenses, transportation costs, and finance lease expense, by the FD&A costs, including changes in FDC, of $0.56/Mcfe on a 1P basis and $0.72/Mcfe on a PDP basis.
| 2016 |
||
| Revenue |
$2.39 |
|
| Realized Gain on Commodity Risk Management |
$0.38 |
|
| Revenue (incl. Realized Gain on Commodity Risk Management) |
$2.77 |
|
| Royalties |
($0.05) |
|
| Operating Expenses |
($0.68) |
|
| Transportation Costs |
($0.31) |
|
| Operating Netback |
$1.73 |
|
| Finance Lease Expense |
($0.28) |
|
| Operating Netback (incl. Finance Lease Expense) |
$1.45 |
|
| Note: See Non-GAAP disclosure in Advisory section |
||
The following tables outline GLJ's estimates of Painted Pony's reserves and associated NPV10 at December 31, 2016 and December 31, 2015:
Summary of Company Working Interest Reserves
| December 31, 2016 |
December 31, 2015 |
|||||
| Natural Gas |
NGLs |
Natural Gas |
Oil |
Oil Equivalent |
||
| Proved Developed Producing |
443.6 |
6.8 |
484.4 |
80.7 |
40.0 |
|
| Proved Developed Non-Producing |
4.4 |
0.0 |
4.5 |
0.8 |
0.7 |
|
| Proved Undeveloped |
1,976.8 |
31.2 |
2,163.8 |
360.6 |
295.8 |
|
| Total Proved |
2,424.8 |
38.0 |
2,652.7 |
442.1 |
336.6 |
|
| Total Probable |
2,092.0 |
32.6 |
2,287.6 |
381.3 |
431.4 |
|
| Total Proved Plus Probable |
4,516.7 |
70.6 |
4,940.3 |
823.4 |
768.0 |
|
| See the advisories with respect to resource definitions. |
||||||
Net Present Values of Future Net Revenue (1)(2)
| (Forecast Prices and Costs; Numbers in this table are subject to rounding) ($Millions) |
||||||
| As at December 31, 2016 |
||||||
| Annual Discount Rate |
0% |
5% |
10% |
15% |
20% |
|
| BEFORE INCOME TAXES |
||||||
| Proved |
||||||
| Developed Producing |
1,233.1 |
890.5 |
705.3 |
591.8 |
515.5 |
|
| Developed Non-Producing |
5.3 |
3.9 |
2.9 |
2.3 |
1.8 |
|
| Undeveloped |
4,430.5 |
2,552.8 |
1,587.1 |
1,033.8 |
690.0 |
|
| Total Proved |
5,668.9 |
3,447.1 |
2,295.3 |
1,627.9 |
1,207.2 |
|
| Probable |
6,242.4 |
2,767.2 |
1,480.5 |
899.5 |
596.1 |
|
| Total Proved Plus Probable |
11,911.3 |
6,214.4 |
3,775.8 |
2,527.3 |
1,803.3 |
|
| (1) |
Estimates of future net revenue, whether discounted or not, do not represent fair market value. |
| (2) |
Future net revenue is after deduction of estimated costs of abandonment and reclamation of existing and future wells that were evaluated by GLJ in the 2016 Reserves Evaluation and does not include costs of abandonment and reclamation of facilities |
Reconciliation of Company Gross Reserves
| (Forecast Prices and Costs; Numbers in this table are subject to rounding) |
||||||
| Natural Gas(1) |
NGLs |
Total |
Total |
|||
| (Bcf) |
(MMbbl) |
(MMboe) |
(Bcfe) |
|||
| Proved Developed Producing Reserves |
||||||
| Opening Balance December 31, 2015 |
218.8 |
3.6 |
40.0 |
240.3 |
||
| Discoveries |
- |
- |
- |
- |
||
| Extensions and Improved Recovery |
246.3 |
4.4 |
45.4 |
272.6 |
||
| Technical Revisions |
15.1 |
(0.7) |
1.8 |
10.9 |
||
| Economic Factors |
- |
(0.0) |
(0.0) |
(0.2) |
||
| Dispositions |
(6.4) |
(0.1) |
(1.1) |
(6.7) |
||
| Acquisitions |
17.4 |
0.2 |
3.1 |
18.4 |
||
| Production |
(47.5) |
(0.6) |
(8.5) |
(51.0) |
||
| Closing Balance December 31, 2016 |
443.6 |
6.8 |
80.7 |
484.4 |
||
| Proved Reserves |
||||||
| Opening Balance December 31, 2015 |
1,829.6 |
31.7 |
336.6 |
2,019.8 |
||
| Discoveries |
- |
- |
- |
- |
||
| Extensions and Improved Recovery |
533.8 |
9.9 |
98.8 |
592.9 |
||
| Technical Revisions |
110.9 |
(3.5) |
15.0 |
89.8 |
||
| Economic Factors |
- |
(0.6) |
(0.6) |
(3.8) |
||
| Dispositions |
(143.6) |
(1.9) |
(25.8) |
(154.8) |
||
| Acquisitions |
141.6 |
3.0 |
26.6 |
159.7 |
||
| Production |
(47.5) |
(0.6) |
(8.5) |
(51.0) |
||
| Closing Balance December 31, 2016 |
2,424.8 |
38.0 |
442.1 |
2,652.7 |
||
| Proved Plus Probable Reserves |
||||||
| Opening Balance December 31, 2015 |
4,152.3 |
76.0 |
768.0 |
4,608.3 |
||
| Discoveries |
- |
- |
- |
- |
||
| Extensions and Improved Recovery |
305.6 |
2.0 |
52.9 |
317.7 |
||
| Technical Revisions |
52.4 |
(7.7) |
1.0 |
6.0 |
||
| Economic Factors |
- |
(0.3) |
(0.3) |
(1.8) |
||
| Dispositions |
(270.7) |
(3.4) |
(48.5) |
(291.2) |
||
| Acquisitions |
324.6 |
4.6 |
58.7 |
352.3 |
||
| Production |
(47.5) |
(0.6) |
(8.5) |
(51.0) |
||
| Closing Balance December 31, 2016 |
4,516.7 |
70.6 |
823.4 |
4,940.3 |
||
| (3) Includes non-associated gas; See advisories re: product type. |
The following table highlights Painted Pony's capital program efficiency.
Capital Efficiencies (1)
| (Forecast Prices and Costs ) |
||||||
| Proved Developed Producing |
2016 |
2015 |
2014 |
3-Year Weighted Avg. |
||
| FD&A ($/Mcfe) |
$0.72 |
$1.38 |
$1.56 |
$1.02 |
||
| Recycle Ratio |
2.0x |
0.9x |
2.0x |
1.8x |
||
| F&D ($/Mcfe) |
$0.75 |
$1.38 |
$2.26 |
$1.23 |
||
| Recycle Ratio |
1.9x |
0.9x |
1.4x |
1.5x |
||
| Proved |
||||||
| FD&A ($/Mcfe) |
$0.56 |
$0.84 |
$1.16 |
$0.81 |
||
| Recycle Ratio |
2.6x |
1.5x |
2.7x |
2.2x |
||
| F&D ($/Mcfe) |
$0.57 |
$0.84 |
$1.35 |
$0.85 |
||
| Recycle Ratio |
2.6x |
1.5x |
2.3x |
2.1x |
||
| Proved Plus Probable |
||||||
| FD&A ($/Mcfe) |
n/a |
$0.16 |
$0.70 |
$0.32 |
||
| Recycle Ratio |
n/a |
7.5x |
4.5x |
5.7x |
||
| F&D ($/Mcfe) |
n/a |
$0.16 |
$0.76 |
$0.35 |
||
| Recycle Ratio |
n/a |
7.5x |
4.1x |
5.1x |
||
| (1) See advisories with respect to finding and development costs. |
||||||
Future Development Costs of Undeveloped Reserves (1)
| (Forecast Prices and Costs) |
||
| 2P Undeveloped |
||
| As at December 31 |
2016 |
2015 |
| Net 2P Undeveloped Wells |
548 |
544 |
| 2P FDC ($Millions, undiscounted) |
2,917 |
3,205 |
| Reserves (Bcfe) |
4,317 |
4,301 |
| 2P FDC per Mcfe |
$0.68 |
$0.75 |
| (Forecast Prices and Costs) |
||
| 1P Undeveloped |
||
| As at December 31 |
2016 |
2015 |
| Net 1P Undeveloped Wells |
339 |
287 |
| 1P FDC ($Millions, undiscounted) |
1,825 |
1,677 |
| Reserves (Bcfe) |
2,164 |
1,775 |
| 1P FDC per Mcfe |
$0.84 |
$0.94 |
| (1) Development costs represents the total development capital less capital associated with the Capital Leases (proved: $1,864.7mm; proved plus probable: $3,023.5mm). |
2017 OPERATIONAL UPDATE
Current Operations
To date in 2017, Painted Pony has drilled 9 (9.0 net) wells and completed 4 (4.0 net) wells. Prior to spring break-up, a further 12 (12.0 net) wells are expected to be drilled and an additional 12 (12.0 net) wells are expected to be completed and production tested. The Corporation currently has five drilling rigs active in the field. The majority of current activity is to develop the production volumes necessary to supply the AltaGas Townsend Facility (the "Facility") with an incremental 48 MMcf/d, which Painted Pony expects to begin flowing to the Facility in August 2017. Painted Pony anticipates supplying an additional 99 MMcf/d to the Facility in October 2017 upon the completion of a 99 MMcf/d Facility expansion project. Painted Pony intends to drill 61 (61.0 net) wells and complete 61 (61.0 net) wells in 2017.
Production
Painted Pony's current productive capacity exceeds 240 MMcfe/d (40,000 boe/d) while first quarter 2017 average production volumes are expected to average approximately 213 – 225 MMcfe/d (35,500 – 37,500 boe/d). This expected level of production is approximately flat to fourth quarter 2016 average daily production volumes due to ongoing shut-ins of adjacent wells during off-set fracing and shut-ins of tested wells for tie-in throughout the first quarter of 2017.
The Corporation expects annual daily volumes will average 288 MMcfe/d (48,000 boe/d) in 2017, exiting 2017 at approximately 408 MMcfe/d (68,000 boe/d). Expected annual average daily production volumes in 2017 represent an increase of 107% over 2016 average daily production volumes of 139.2 Mcfe/d (23,204 boe/d).
TRANSPORTATION, HEDGING AND PRICING
In order to protect cash flow, capital investment and production profiles, Painted Pony sells natural gas using a combination of financial hedges and firm physical delivery transactions, supported by firm transportation contracts. Painted Pony has been successful in diversifying sales contracts to AECO, Station 2, and Sumas through a combination of these strategies.
Transportation Firm Capacity
Currently Painted Pony has 201 MMcf/d of firm transportation on the Spectra pipeline system in northeast BC and an additional 45 MMcf/d of firm transportation into AECO on the Nova Gas Transmission Ltd ("NGTL") system at Groundbirch, BC.
Through successful bids via open seasons on the Spectra pipeline system in northeast BC in 2015 and 2016, Painted Pony has added additional firm transportation of 220 MMcf/d, (expected to be in-service December 2017) and 250 MMcf/d (expected in-service December 2018). This will bring Painted Pony's firm transportation on the Spectra system to 357 MMcf/d by year-end 2017 and 577 MMcf/d by year-end 2018. In addition, Painted Pony has committed to an additional 130 MMcf/d of firm transportation on NGTL at Groundbirch via the TCPL Towerbirch Expansion Project (expected to be in-service November 2017). By November 2017, the Corporation will have 174 MMcf/d of firm transportation on NGTL at Groundbirch, supplied by Painted Pony's natural gas on the Spectra system. This portfolio of contracts provides certainty of long-term firm natural gas transportation for Painted Pony's growing British Columbia production base and provides AECO pricing on a significant portion of Painted Pony's natural gas production.
Transportation and Hedging
Painted Pony has executed physical delivery contracts which further diversify the Corporation's access to sales hubs. From November 2016 to August 2017, the Corporation has 194 MMcf/d of AECO and Sumas indexed contracts. These contracts have a variety of terms and fixed differentials and, when combined with financial contracts, reduce Painted Pony's exposure to Station 2 spot pricing to less than 13% (28 MMcf/d) of forecasted natural gas production during this period.
Painted Pony hedges certain production volumes to provide balance sheet and capital spending protection. For 2017, 2018 and 2019, Painted Pony has the following financial hedges in place:
| Financial AECO Natural Gas Contracts |
||||
| Reference |
Volume |
Term |
Weighted Average |
Options Traded |
| CDN$ AECO |
90,000 |
Q1 2017 |
2.87 |
Swaps |
| CDN$ AECO |
75,000 |
Q2 2017 |
2.85 |
Swaps |
| CDN$ AECO |
90,000 |
Q3 2017 |
2.86 |
Swaps |
| CDN$ AECO |
145,000 |
Q4 2017 |
2.89 |
Swaps |
| CDN$ AECO |
71,000 |
Q1 2018 |
2.93 |
Swaps |
| CDN$ AECO |
71,000 |
Q2 2018 |
2.85 |
Swaps |
| CDN$ AECO |
50,000 |
Q3 2018 |
2.81 |
Swaps |
| CDN$ AECO |
24,000 |
Q4 2018 |
2.72 |
Swaps |
| CDN$ AECO |
18,000 |
Q1 2019 |
2.64 |
Swaps |
| CDN$ AECO |
18,000 |
Q2 2019 |
2.64 |
Swaps |
| CDN$ AECO |
25,000 |
Q4 2017 – Q4 2019 |
2.88 |
Call Options |
| Financial Station 2 Natural Gas Contracts |
||||
| Reference |
Volume |
Term |
Weighted Average |
Options Traded |
| CDN$ Station 2 |
75,000 |
Q1 2017 |
1.82 |
Swaps |
| CDN$ Station 2 |
90,000 |
Q2 2017 |
1.90 |
Swaps |
| CDN$ Station 2 |
100,000 |
Q3 2017 |
1.93 |
Swaps |
| CDN$ Station 2 |
120,000 |
Q4 2017 |
2.07 |
Swaps |
| CDN$ Station 2 |
105,000 |
Q1 2018 |
2.04 |
Swaps |
| CDN$ Station 2 |
42,000 |
Q2 2018 |
2.38 |
Swaps |
| CDN$ Station 2 |
37,000 |
Q3 2018 |
2.36 |
Swaps |
| CDN$ Station 2 |
37,000 |
Q4 2018 |
2.36 |
Swaps |
| CDN$ Station 2 |
37,000 |
Q1 2019 |
2.36 |
Swaps |
| CDN$ Station 2 |
37,000 |
Q2 2019 |
2.36 |
Swaps |
| CDN$ Station 2 |
25,000 |
Q3 2019 |
2.37 |
Swaps |
| CDN$ Station 2 |
10,000 |
Q4 2019 |
2.45 |
Swaps |
| Financial WTI Crude Oil Contracts |
||||
| Reference |
Volume |
Term |
Weighted Average |
Options Traded |
| CDN$ WTI |
500 |
Q1 2017 – Q4 2017 |
70.05 |
Swaps |
| CDN$ WTI |
500 |
Q1 2018 – Q4 2019 |
70.20 |
Swaps |
Subsequent to December 31, 2016, Painted Pony entered into an additional commodity risk management contract as follows:
| Reference |
Volume |
Term |
Weighted Average |
Options Traded |
| CDN$ AECO |
10,000 |
Q1 2018 |
3.16 |
Swaps |
2016 FINANCIAL AND OPERATING RESULTS
Capital Expenditures
Exploration and development capital expenditures for 2016 of $203.5 million were approximately $9.0 million less than forecasted and included $152.9 million on drilling and completions activity. During 2016, the Corporation drilled 36 (36.0 net) wells targeting Montney natural gas. Expenditures on facilities and equipment during the year totaled $43.8 million and included wellsite facilities costs, pipeline construction costs and spending on compression and dehydration facilities. During the fourth quarter of 2016, Painted Pony's capital expenditures were $51.3 million, approximately $9.0 million less than forecasted while still meeting forecasted production volumes targets.
Production
Annual average daily production volumes increased 49% compared to the year ended December 31, 2015 underscoring strong year-over-year organic growth. Fourth quarter 2016 average daily production volumes increased approximately 144% to 220.2 MMcfe/d (36,695 boe/d) compared to the fourth quarter of 2015 when average daily production volumes totaled 90.3 MMcfe/d (15,043 boe/d).
Funds Flow from Operations
Painted Pony generated record funds flow from operations of $26.5 million ($0.26/share) during the fourth quarter of 2016, compared to $2.6 ($0.03/share) million during the fourth quarter of 2015. The increase was primarily a result of increased production and decreased cash operating costs (royalties, operating expenses and transportation costs).
During the three months and year ended December 31, 2016, the Corporation realized natural gas prices that represented discounts of 11% and 6%, respectively, to the AECO daily spot price. This compares to discounts of 35% and 22% to the AECO daily spot price realized in the three months and year ended December 31, 2015.
For the year ended December 31, 2016, the Corporation increased funds flow from operations 95% to $55.6 million compared to $28.5 million during the year ended December 31, 2015. The increase was a result of increased production, decreased operating and transportation expenses, and a $19.9 million gain on commodity risk management in 2016.
Cash Operating Costs and Netbacks
Painted Pony improved its cash operating costs (royalties, operating expenses and transportation costs) on a per Mcfe basis in 2016 to $1.04/ Mcfe, a 24% reduction from $1.36/Mcfe in 2015.
Royalties
Royalties in 2016 were $0.05/Mcfe, or 2.2% of revenue, compared with $0.06/Mcfe in 2015, or 2.5% of revenue. For 2017, Painted Pony expects royalty rates to be approximately 3.0% of revenue because of royalty credits. This estimate considers the combined impact of incremental sales volumes from newly drilled wells that will qualify for royalty holidays, net of royalties paid on wells that have obtained the full benefit of provincial royalty incentives.
Operating Costs
Painted Pony's operating costs decreased by 28% in 2016 to $0.68/Mcfe from $0.94/Mcfe in 2015. This marks the second consecutive year of annual operating cost reductions in excess of 25%. Higher production volumes in the fourth quarter of 2016 lowered operating costs as fixed costs were spread over a larger production base, lowering per Mcfe costs. Also, the capital fee associated with the Townsend Facility, which began operations in the third quarter of 2016, is classified separately from operating costs, with the interest portion of the capital fee included in finance expenses.
The Corporation expects that average per Mcfe operating costs in 2017 will be in the range of $0.45 to $0.55/Mcfe, assuming normal seasonal weather conditions.
Transportation
Transportation costs for the fourth quarter of 2016 increased by $0.07/Mcfe or 23%, compared to the fourth quarter of 2015 due to a 416% increase in NGL volumes, which have higher transportation costs. NGL production volumes increased 416% to 3,177 bbls/d during the fourth quarter of 2016 compared to 616 bbls/d during the fourth quarter of 2015.
Painted Pony successfully negotiated access to alternate delivery points that lowered NGL trucking costs which decreased Painted Pony's full-year 2016 transportation costs 14% or $0.05/Mcfe, to $0.31/Mcfe in 2016 from $0.36/Mcfe in 2015.
For 2017, the Corporation expects average per unit transportation costs to be approximately $0.35 - $0.40/Mcfe.
General and Administrative Costs
Due to significantly higher volumes in the fourth quarter of 2016 and ongoing cost control, general and administrative ("G&A") expenses in the fourth quarter of 2016 decreased 69% to $0.17/Mcfe compared to $0.55/Mcfe in the fourth quarter of 2015.
Due to forecasted higher production volumes in 2017 and a continued focus on costs, Painted Pony expects 2017 G&A expenses to be approximately $0.10 - $0.12/Mcfe.
Interim CFO Appointment
Effective immediately Mr. John Van de Pol, Senior Vice President and Chief Financial Officer ("CFO") is taking a short-term medical leave to recover from minor eye surgery. The leave is expected to last one to two weeks. Mr. Stuart Jaggard, Vice President and Controller, has been appointed Interim CFO of the Corporation. Mr. Jaggard joined Painted Pony as Vice President and Controller in October 2014.
FINANCIAL HIGHLIGHTS
| Three Months Ending |
||||
| ($000s, except where noted) |
Dec. 31, |
Dec. 31, |
Change |
|
| Petroleum and natural gas revenue(1) |
65,155 |
15,048 |
333% |
|
| Funds flow from operations (2) |
26,501 |
2,572 |
930% |
|
| Per share – basic (3) and diluted (4) |
0.26 |
0.03 |
767% |
|
| Net income (loss) |
(27,761) |
2,550 |
(1,189)% |
|
| Per share – basic (3) and diluted (4) |
(0.28) |
0.02 |
(1,500)% |
|
| Cash Capital expenditures |
51,506 |
14,567 |
254% |
|
| Working capital deficiency (5) |
(73,647) |
(4,629) |
1,491% |
|
| Bank debt |
200,836 |
63,626 |
216% |
|
| Net debt (6) |
228,463 |
77,361 |
195% |
|
| Total assets |
1,336,955 |
781,574 |
71% |
|
| Decommissioning obligations |
29,857 |
21,480 |
39% |
|
| Average daily production volumes (boe/d) |
36,695 |
15,043 |
144% |
|
| Average daily production volumes (MMcfe/d) |
220.2 |
90.3 |
144% |
|
| Realized commodity prices |
||||
| Natural gas ($/Mcf) |
2.78 |
1.60 |
74% |
|
| NGLs ($/bbl) |
46.62 |
40.51 |
15% |
|
| Total ($/Mcfe) |
3.22 |
1.81 |
78% |
|
| Operating netbacks ($/Mcfe) (7) |
2.09 |
0.96 |
118% |
|
| 1. |
Before royalties. |
| 2. |
Funds flow from operations and funds flow from operations per share (basic and diluted) are non-GAAP measures used to represent cash flow from operating activities before the effects of changes in non-cash working capital, DSU expense and decommissioning expenditures. Funds flow from operations per share is calculated by dividing funds flow from operations by the weighted average number of basic or diluted shares outstanding in the period. See "Non-GAAP Measures". |
| 3. |
Basic per share information is calculated on the basis of the weighted average number of shares outstanding in the period. |
| 4. |
Diluted per share information reflects the potential dilutive effect of stock options. |
| 5. |
Working capital deficiency is a non-GAAP measure calculated as current assets less current liabilities. See "Non-GAAP Measures". |
| 6. |
Net debt is a non-GAAP measure calculated as bank debt and working capital deficiency, adjusted for the current portion of fair value of risk management contracts. See "Non-GAAP Measures". |
| 7. |
Operating netbacks is a non-GAAP measure calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on commodity risk management, less royalties, operating expenses and transportation costs. See "Non-GAAP Measures" and "Operating Netbacks". |
FINANCIAL HIGHLIGHTS
| Year ended December 31, |
||||
| 2016 |
2015 |
Change |
||
| Financial ($ millions, except per share and shares outstanding) |
||||
| Petroleum and natural gas revenue(1) |
121.6 |
81.6 |
49% |
|
| Funds flow from operations(2) |
55.6 |
28.5 |
95% |
|
| Per share – basic(3) and diluted(4) |
0.56 |
0.29 |
93% |
|
| Net loss |
(51.9) |
(5.2) |
898% |
|
| Per share – basic(3) and diluted(4) |
(0.52) |
(0.05) |
940% |
|
| Capital expenditures |
204.4 |
106.7 |
92% |
|
| Working capital deficiency (5) |
(73.6) |
(4.6) |
1,500% |
|
| Net debt (6) |
228.5 |
77.4 |
195% |
|
| Bank debt |
200.8 |
63.6 |
216% |
|
| Total assets |
1,337.0 |
781.6 |
71% |
|
| Shares outstanding (millions) |
100.2 |
100.0 |
- |
|
| Basic / fully diluted weighted-average shares (millions) |
100.1 |
99.8 |
- |
|
| Operational |
||||
| Daily production volumes |
||||
| Natural gas (MMcf/d) |
129.9 |
88.7 |
46% |
|
| Natural gas liquids (bbls/d) |
1,557 |
826 |
88% |
|
| Total (MMcfe/d) |
139.2 |
93.6 |
49% |
|
| Total (boe/d) |
23,204 |
15,604 |
49% |
|
| Realized commodity prices |
||||
| Natural gas ($/Mcf) |
2.04 |
2.10 |
(3%) |
|
| Natural gas liquids ($/bbl) |
43.49 |
44.30 |
(2%) |
|
| Total ($/Mcfe) |
2.39 |
2.39 |
- |
|
| Operating netbacks ($/Mcfe) (7) |
1.73 |
1.23 |
41% |
|
| 1. |
Before royalties. |
| 2. |
Funds flow from operations and funds flow from operations per share (basic and diluted) are non-GAAP measures used to represent cash flow from operating activities before the effects of changes in non-cash working capital, DSU expense and decommissioning expenditures. Funds flow from operations per share is calculated by dividing funds flow from operations by the weighted average number of basic or diluted shares outstanding in the period. See "Non-GAAP Measures". |
| 3. |
Basic per share information is calculated on the basis of the weighted average number of shares outstanding in the period. |
| 4. |
Diluted per share information reflects the potential dilutive effect of stock options. |
| 5. |
Working capital deficiency is a non-GAAP measure calculated as current assets less current liabilities. See "Non-GAAP Measures". |
| 6. |
Net debt is a non-GAAP measure calculated as bank debt and working capital deficiency, adjusted for the current portion of fair value of risk management contracts. See "Non-GAAP Measures". |
| 7. |
Operating netbacks is a non-GAAP measure calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on commodity risk management, less royalties, operating expenses and transportation costs. See "Non-GAAP Measures" and "Operating Netbacks". |
DEFINITIONS AND ADVISORIES
Independent Reserves Evaluation
GLJ Petroleum Consultants ("GLJ"), independent qualified reserves evaluators of Calgary, Alberta, prepared a reserves estimation and economic evaluation of the Corporation's oil and natural gas properties effective December 31, 2016, which is contained in a report dated February 27, 2017 (the "2016 Reserves Report"). GLJ prepared reserves estimations and economic evaluations of the Corporation's reserves effective December 31, 2016. Reserves estimates stated herein as at December 31 of a year are extracted from the relevant evaluation.
The 2016 Reserves Report and the prior reserves evaluation were prepared in accordance with the standards contained in the Canadian Oil & Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), which were in effect at the time of the evaluation.
The reserves data provided in this press release contains only excerpts of the disclosure required under NI 51-101. All of the required information will be contained in the Corporation's Annual Information Form for the year ended December 31, 2016, which will be filed on SEDAR on or before March 31, 2017.
Currency: All amounts referred to in this press release are stated in Canadian dollars unless otherwise specified.
Product Type: NI 51-101 requires a reporting issuer to disclose its reserves in accordance with the product types contained in NI 51-101, which product types include conventional natural gas, shale rock and natural gas liquids. "Shale gas" as defined in NI 51-101 means natural gas: (i) contained in dense organic-rick rocks, including low-permeability shales, siltstones and carbonites, in which the natural gas is primarily absorbed on the kerogen or clay minerals; and (ii) usually requires the use of hydraulic fracturing to achieve economic production rates. Shale gas is the NI 51-101 product type that most closely matches the natural gas from the Corporation's properties.
Forecast Prices and Costs: Reserves estimates stated herein are calculated using the forecast price and cost assumptions by the reserves evaluator which were in effect at the time of the applicable reserves evaluation. The complete GLJ January 1, 2016 price forecast is available on its website at gljpc.com. At the time of the 2016 Reserves Evaluation the Corporation's 2017 capital expenditure budget was $319 million. Forecast expenditures in future years may vary from actual expenditures.
Company Gross Reserves: In this press release, unless otherwise stated, references to "reserves" are to the Corporation's gross reserves, defined as the Corporation's working interest (operated or non- operated) share before deduction of royalties and without including any royalty interests of the Corporation.
Rounding: Numbers in tables may not add due to rounding.
Estimated Future Net Revenues: Estimated future net revenues are stated before deducting income taxes and future estimated site restoration costs and are reduced for estimated future abandonment costs and estimated capital for future development associated with the reserves. The undiscounted and discounted net present values disclosed do not represent the fair market value of the reserves.
Reserves for Portion of Properties: With respect to the disclosure of reserves contained herein relating to portions of the Corporation's properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation.
Finding and Development Costs: With respect to disclosure of finding and development ("F&D") costs and finding, development and acquisition costs ("FD&A") costs disclosed in this press release:
- F&D costs both including and excluding acquisitions and dispositions have been presented in this press release. While NI 51-101 requires the calculation of F&D costs to eliminate the effects of acquisitions and dispositions, FD&A costs have also been presented because acquisitions and dispositions can have a significant impact on the Corporation's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Corporation's cost structure.
- F&D costs for each of the years 2016, 2015 and 2014 are calculated by dividing the total of the exploration costs, development costs and the change during the most recent financial year in estimated future development capital relating to either proved reserves or 2P reserves, by the additions to either proved reserves or 2P reserves during the most recent financial year.
- The aggregate of the exploration and development costs incurred in the most recent financial year and any change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year.
Future Development Costs: With respect to future development costs, there can be no guarantee that in the future, funds will be available or that the Corporation will allocate funds to develop all of the attributed reserves. Failure to develop these reserves would have a negative impact on future production and cash flow estimated by GLJ. Year-end 2016 future development costs excluded capital costs associated with the Capital Leases of the AltaGas Townsend Expansion Facilities. In 2016, the proved capital costs associated with the Capital Leases was $39 million (undiscounted). In 2016, proved plus probable capital costs associated with the Capital Leases was $107 million (undiscounted).
Reserves Replacement: Reserves replacement is calculated by dividing proved developed producing reserves, proved reserves or proved plus probable reserves additions, as applicable, before production by total production in the applicable period. Reserves replacement may be used as a measure of a company's sustainability and its ability to replace its reserves.
Recycle Ratios: Recycle ratios are calculated by dividing the average operating netback per boe of Mcfe, or funds flow netback per boe or Mcfe, by F&D costs and FD&A costs, as applicable. Recycle ratios may be used as a measure of a company's profitability.
boe Conversions: Barrel of oil equivalent ("boe") amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel of oil (1 bbl). Boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 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.
Mcfe, Bcfe and Tcfe Conversions: Thousands of cubic feet of gas equivalent ("Mcfe"), billions of cubic feet of gas equivalent ("Bcfe") and trillions of cubic feet of gas equivalent ("Tcfe") amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas. Mcfe, Bcfe and Tcfe amounts may be misleading, particularly if used in isolation. A conversion ratio of 1 bbl to 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Non-GAAP Financial Measures: This press release contains the terms, "working capital (deficiency)", "operating netbacks", and "operating netbacks (incl. Finance Lease Expense)" which do not have any standardized meanings prescribed by generally accepted accounting principles ("GAAP") and therefore may not be comparable with the calculation of similar measures for other entities. Management calculates working capital deficiency as current assets less current liabilities and uses this ratio to analyze operating performance and leverage. Operating netbacks is calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on commodity risk management, less royalties, operating expenses and transportation costs. Operating netbacks (incl. Finance Lease Expense) are calculated by adjusting operating netbacks for finance lease expenses.
Forward-Looking Information: This press release contains certain forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to future events or future performance and is based upon the Corporation's current internal expectations, estimates, projections, assumptions and beliefs. All information other than historical fact is forward-looking information. Information relating to reserves is forward looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves exist in quantitates predicted or estimated and that the reserves can be profitably produced in the future. Words such as "plan", "expect", "intend", "believe", "anticipate", "estimate", "may", "will", "potential", "proposed" and other similar words that indicate events or conditions may occur are intended to identify forward-looking information. In particular, this press release contains forward looking information relating to estimates of recoverable reserves volumes and the future net revenues associated with those reserves; expected results from the Corporation's assets and results of operations; price forecasts; future development capital; decline rates; operating cost reductions will reduce costs over the long-term; credit facilities will be maintained a current levels; the 2017 capital program will be executed; the expansion of the AltaGas Townsend Facility will be constructed in the time frame anticipated; contracted firm transportation will become available;
Forward-looking information is based on assumptions including but not limited to future commodity prices, currency exchange rates, drilling success, production rates future capital expenditures and the availability of labor and services. With respect to estimates of reserves, a key assumption is that the data used by GLJ in their independent reserves evaluation is valid. With respect to future wells, a key assumption is the validity of geological and technical interpretations performed by the Corporation's technical staff, which indicate that commercially economic volumes can be recovered from the Corporation's lands. Estimates as to average annual production assume that no material unexpected outages occur in the infrastructure the Corporation relies upon to produce its wells, that existing wells continue to meet production expectations and that future wells scheduled to come on production in 2017 meet timing and production rate expectations.
Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans, intentions or expectations on which they are based will occur. Although the Corporation's management believes that the expectations in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct.
Forward-looking information necessarily involves both known and unknown risks associated with oil and gas exploration, production, transportation and marketing. There are risks associated with the uncertainty of geological and technical data, imprecision of reserve estimates, operational risks, risks associated with drilling and completions, environmental risks, risks of the change in government regulation of the oil and gas industry, risks associated with competition from others for scarce resources and risks associated with general economic conditions affecting the Corporation's ability to access sufficient capital. Additional information on these and other risk factors that could affect operational or financial results are included in the Corporation's most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities.
Forward-looking information is based on estimates and opinions of management at the time the information is presented. The Corporation is not under any duty to update the forward-looking information after the date of this press release to revise such information to actual results or to changes in the Corporation's plans or expectations, except as required by applicable securities laws.
Any "financial outlook" contained in this press release, as such term is defined by applicable securities laws, is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautions that reliance on such information may not be appropriate for other purposes.
ABBREVIATIONS
| Natural Gas |
Natural Gas Liquids |
||
| Mcf |
thousand cubic feet |
bbls |
barrels |
| Mcf/d |
thousand cubic feet per day |
bbls/d |
barrels per day |
| MMcf/d |
million cubic feet per day |
NGLs |
natural gas liquids |
| Bcf |
Billion cubic feet |
Mcfe |
thousand cubic feet equivalent |
| Bcfe |
Billion cubic feet equivalent |
Mcfe/d |
thousand cubic feet equivalent per day |
| Tcfe |
Trillion cubic feet per day |
||
| boe |
barrels of oil equivalent |
||
| boe/d |
barrels of oil equivalent per day |
||
ABOUT PAINTED PONY
Painted Pony is a publicly-traded natural gas Corporation based in Western Canada. The Corporation is primarily focused on the development of natural gas and natural gas liquids from the Montney formation in northeast British Columbia. Painted Pony's common shares trade on the Toronto Stock Exchange under the symbol "PPY".
SOURCE Painted Pony Petroleum Ltd.
Patrick R. Ward, President and CEO, (403) 475-0440; Stuart W. Jaggard, Vice President and Interim CFO, (403) 475-0440; Jason Fleury, Director, Investor Relations, (403) 776-3261
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