CALGARY, ALBERTA–(Marketwired – Feb. 24, 2016) – Pengrowth Energy Corporation (TSX:PGF) (NYSE:PGH) is pleased to announce its financial and operating results for the fourth quarter and the full year 2015, as well as 2015 year end reserves results.
Pengrowth achieved strong operational performance, executing and delivering on its commitments despite the challenging environment that persisted in 2015. The Company achieved production on the high end of guidance, despite an 80 percent reduction in capital spending year over year and asset sales representing approximately 13 percent of base production. The Company successfully executed the start-up of the first commercial phase of Lindbergh, with production from Lindbergh exceeding 16,000 barrels per day (bbl per day) for the first time during five days in early December at an instantaneous steam oil ratio (ISOR) of 2.0 and averaging 15,098 bbl per day at an ISOR of 2.1 from activities in the month. Pengrowth continued to benefit from its robust commodity hedging program, which has been providing strength and stability to cash flows. As a result of this program, Pengrowth was able to realize $327 million of hedging gains in 2015 and delivered full year funds flow of $459.3 million and cash flow after capital expenditures of $275.5 million.
The Company was proactive as commodity prices declined throughout the year, taking several measures to ensure its ability to respond to the lower price environment. A strong focus on cost management allowed the Company to generate significant cost savings across all segments of its business and cost reduction efforts resulted in full year operating expenses and general and administrative expenses (G&A) that were below corporate guidance. Pengrowth also focused its attention on debt reduction, with efforts resulting in the Company being able to pay down approximately $280 million of debt from disposition proceeds and funds flow from operations.
2015 Operational, Financial and Reserves Highlights:
- Full year 2015 funds flow of $459.3 million ($0.85 per share) was down only nine percent year over year while average commodity prices decreased by 43 percent year over year, primarily as a result of Pengrowth’s strong commodity risk management gains.
- Realized $327 million of commodity risk management gains in 2015. The remaining value of Pengrowth’s unrealized foreign exchange, power and commodity price hedges was $599 million, as at February 19, 2016.
- Focused efforts on reducing debt as the Company was successful in paying down approximately $280 million of debt from disposition proceeds and funds flow from operations.
- Successfully executed the ramp-up of the Lindbergh thermal project, with fourth quarter production in excess of the 12,500 bbl per day nameplate capacity, averaging 14,274 bbl per day at an ISOR of 2.1 and December average production of 15,098 bbl per day at an ISOR of 2.1.
- Delivered strong operational performance with fourth quarter production averaging 67,934 barrels of oil equivalent per day (boe per day), including the impact of asset dispositions in the quarter. Full year 2015 annual production averaged 71,409 boe per day, which was at the high end of guidance of 70,000 boe per day to 72,000 boe per day and also included the impacts of asset dispositions, shut-in uneconomic production and a significantly reduced capital program.
- Recorded an adjusted net loss of $463.4 million ($0.85 per share) in the fourth quarter and $811.4 million ($1.50 per share) for the full year. The losses resulted from non-cash, impairment charges on mature assets of approximately $518.5 million ($414 million after-tax) in the fourth quarter and $1,000.5 million ($789 million after-tax) for the full year, respectively. Continued weakness in commodity prices coupled with a reduction in the price forecast for oil and natural gas were the main reasons for the impairments.
- Successfully replaced 282 percent of 2015 production with proved plus probable (2P) reserves additions before the impact of dispositions and 145 percent of 2015 production net of dispositions.
- Achieved 2015 finding and development (F&D) costs of $7.12 per boe including changes in future development costs (FDC) for 2P reserves, resulting in a recycle ratio of 3.5 using a 2015 average corporate netback of $24.97 per boe.
- Year end 2015 estimated net asset value (NAV) per share of $3.75.
Derek Evans, President and Chief Executive Officer, said “In 2015 we have delivered the operating results that we said we would, notwithstanding the continued deterioration in the commodity price environment that persisted throughout the year. We delivered on our Lindbergh commitments with production substantially exceeding nameplate capacity by the end of 2015. We also achieved the high end of our production guidance despite significant asset sales. Our ongoing cost reduction initiatives resulted in operating and G&A expenses that were below the low end of corporate guidance and, most importantly, we were able to reduce our debt position by $280 million from funds flow and proceeds from our ongoing disposition program. Even with significant asset divestitures, we still managed to achieve 2P reserves additions equivalent to 145 percent of 2015 production at a 2P F&D cost of $7.12 per boe, including changes in FDC. In 2016 we will continue our prudent and proactive responses to this low commodity price environment with the suspension of our dividend and a lean capital program. We intend to apply excess cash flow and proceeds from our ongoing disposition program to debt reduction.”
Summary of Financial & Operating Results | |||||||||||||||||
Three months ended | Twelve months ended | ||||||||||||||||
(monetary amounts in millions except per boe and per share amounts) | Dec 31, 2015 | Dec 31, 2014 | % Change (3) | Dec 31, 2015 | Dec 31, 2014 | % Change (3) | |||||||||||
PRODUCTION | |||||||||||||||||
Average daily production (boe/d) | 67,934 | 71,802 | (5 | ) | 71,409 | 73,288 | (3 | ) | |||||||||
FINANCIAL | |||||||||||||||||
Funds flow from operations (1) (2) | $ | 114.2 | $ | 115.8 | (1 | ) | $ | 459.3 | $ | 505.7 | (9 | ) | |||||
Funds flow from operations per share (1) (2) | $ | 0.21 | $ | 0.22 | (5 | ) | $ | 0.85 | $ | 0.96 | (11 | ) | |||||
Oil and gas sales | $ | 169.1 | $ | 291.5 | (42 | ) | $ | 830.8 | $ | 1,496.9 | (44 | ) | |||||
Oil and gas sales per boe | $ | 27.06 | $ | 44.13 | (39 | ) | $ | 31.88 | $ | 55.96 | (43 | ) | |||||
Realized commodity risk management gains (losses) | $ | 97.7 | $ | 21.7 | 350 | $ | 327.0 | $ | (96.1 | ) | (440 | ) | |||||
Realized commodity risk management gains (losses) per boe | $ | 15.63 | $ | 3.29 | 375 | $ | 12.55 | $ | (3.60 | ) | (449 | ) | |||||
Operating expenses | $ | 81.4 | $ | 94.5 | (14 | ) | $ | 372.1 | $ | 415.4 | (10 | ) | |||||
Operating expenses per boe | $ | 13.02 | $ | 14.31 | (9 | ) | $ | 14.28 | $ | 15.53 | (8 | ) | |||||
Royalty expenses | $ | 19.1 | $ | 51.2 | (63 | ) | $ | 89.5 | $ | 268.6 | (67 | ) | |||||
Royalty expenses per boe | $ | 3.06 | $ | 7.75 | (61 | ) | $ | 3.43 | $ | 10.04 | (66 | ) | |||||
Royalty expenses as a percent of sales | 11.3 | % | 17.6 | % | 10.8 | % | 17.9 | % | |||||||||
Operating netback per boe (1) | $ | 25.07 | $ | 24.04 | 4 | $ | 24.97 | $ | 25.64 | (3 | ) | ||||||
Cash G&A expenses (1) | $ | 15.8 | $ | 21.2 | (25 | ) | $ | 87.0 | $ | 84.3 | 3 | ||||||
Cash G&A expenses per boe (1) | $ | 2.53 | $ | 3.21 | (21 | ) | $ | 3.34 | $ | 3.15 | 6 | ||||||
Capital expenditures | $ | 19.1 | $ | 258.8 | (93 | ) | $ | 183.8 | $ | 904.0 | (80 | ) | |||||
Net cash dispositions (3) | $ | (183.4 | ) | $ | (19.8 | ) | $ | (209.6 | ) | $ | (67.5 | ) | 211 | ||||
Dividends paid | $ | 5.5 | $ | 63.8 | (91 | ) | $ | 122.3 | $ | 253.2 | (52 | ) | |||||
Dividends paid per share | $ | 0.01 | $ | 0.12 | (92 | ) | $ | 0.23 | $ | 0.48 | (52 | ) | |||||
Number of shares outstanding at period end (000’s) | 543,033 | 533,438 | 2 | 543,033 | 533,438 | 2 | |||||||||||
Weighted average number of shares outstanding (000’s) | 543,033 | 531,654 | 2 | 539,951 | 527,851 | 2 | |||||||||||
STATEMENT OF INCOME (LOSS) | |||||||||||||||||
Adjusted net income (loss) (1) | $ | (463.4 | ) | $ | (854.8 | ) | (46 | ) | $ | (811.4 | ) | $ | (879.0 | ) | (8 | ) | |
Net income (loss) | $ | (468.6 | ) | $ | (506.0 | ) | (7 | ) | $ | (1,093.1 | ) | $ | (578.8 | ) | 89 | ||
Net income (loss) per share | $ | (0.86 | ) | $ | (0.95 | ) | (9 | ) | $ | (2.02 | ) | $ | (1.10 | ) | 84 | ||
DEBT (4) | |||||||||||||||||
Senior debt | $ | 1,719.5 | $ | 1,722.0 | – | ||||||||||||
Convertible debentures | $ | 137.0 | $ | 137.2 | – | ||||||||||||
Total debt before working capital | $ | 1,856.5 | $ | 1,859.2 | – | ||||||||||||
Total debt including working capital | $ | 1,671.2 | $ | 1,836.5 | (9 | ) | |||||||||||
CONTRIBUTION BASED ON OPERATING NETBACKS (1) | |||||||||||||||||
Light oil | 52 | % | 50 | % | 54 | % | 55 | % | |||||||||
Heavy oil | 42 | % | 17 | % | 37 | % | 17 | % | |||||||||
Natural gas liquids | 4 | % | 11 | % | 2 | % | 11 | % | |||||||||
Natural gas | 2 | % | 22 | % | 7 | % | 17 | % | |||||||||
PROVED PLUS PROBABLE RESERVES | |||||||||||||||||
Light oil (Mbbls) | 68,510 | 91,695 | (25 | ) | |||||||||||||
Heavy oil (Mbbls) | 273,194 | 272,610 | – | ||||||||||||||
Natural gas liquids (Mbbls) | 28,477 | 34,261 | (17 | ) | |||||||||||||
Natural gas (Bcf) | 1,194 | 953 | 25 | ||||||||||||||
Total oil equivalent (Mboe) | 569,126 | 557,350 | 2 | ||||||||||||||
CAPITAL PERFORMANCE (1) | |||||||||||||||||
Finding & Development (“F&D“) cost per boe (1)(5) | $ | 7.12 | $ | 22.33 | (68 | ) | |||||||||||
Recycle ratio (1)(6) | 3.5 | 1.1 | 218 |
(1) | See the Non-GAAP and Operational Measures disclosures at end of this release. |
(2) | Funds flow from operations for the three and twelve months ended December 31, 2015 excludes $0.2 million and $94.1 million, respectively, of gains related to the 2015 settlement of foreign exchange swap contracts. |
(3) | Percentage changes in excess of 500 are excluded. |
(4) | Debt includes the current and long term portions. |
(5) | Includes changes in FDC and based on 2P reserves. |
(6) | Recycle ratio is calculated as operating netback per boe divided by F&D costs per boe based on 2P reserves. |
Funds Flow from Operations
Fourth quarter 2015 funds flow from operations of $114.2 million ($0.21 per share) decreased five percent compared to $120.6 million ($0.22 per share) in the third quarter 2015. Lower commodity prices and the absence of volumes associated with the property dispositions contributed to the lower funds flow in the quarter. Offsetting the impact of lower commodity prices were higher realized commodity risk management gains, lower operating, cash G&A and other expenses.
Full year 2015 funds flow from operations of $459.3 million ($0.85 per share) decreased nine percent compared to $505.7 million ($0.96 per share) in 2014. The decrease in funds flow from operations was due to lower commodity prices and higher interest and financing charges, which were largely offset by realized commodity risk management gains, along with lower royalties and operating expenses.
Production
Pengrowth’s fourth quarter average daily production of 67,934 boe per day decreased eight percent compared to 74,239 boe per day in the third quarter of 2015, due largely to the property dispositions which closed in the quarter.
Full year 2015 average production of 71,409 boe per day was on the high end of corporate guidance of 70,000 to 72,000 boe per day, despite the impacts of shut-in uneconomic production, asset dispositions and a significantly reduced capital program. Compared to 2014 full year average production of 73,288 boe per day, full year 2015 production decreased approximately three percent, primarily as a result of the absence of volumes associated with asset dispositions late in the year, production declines related to 2015 capital development curtailments and approximately 1,000 boe per day of shut-in uneconomic production. Offsetting these volumes were the inclusion of Lindbergh Phase 1 production commencing April 1, 2015 and additions from the 2014 Groundbirch development program.
Lindbergh
Lindbergh, Pengrowth’s 100 percent owned and operated thermal project, is located in the Cold Lake area of eastern Alberta. The project offers Pengrowth the potential to ultimately develop annual production of 40,000 to 50,000 bbl per day, starting with the initial 12,500 bbl per day commercial phase which came on-stream in 2015.
In 2015, Pengrowth successfully executed the start-up of the first commercial phase of Lindbergh, following first steam in December 2014 and declaring commerciality on April 1, 2015. Production ramp-up progressed throughout the year, averaging approximately 10,500 bbl per day for the year (based on only nine months of commercial production).
Fourth quarter production at Lindbergh averaged 14,274 bbl per day with an ISOR of 2.1. Production in the quarter was somewhat tempered by a scheduled partial plant turnaround in November, as well as minor production interruptions. Production ramp-up resumed following the turnaround with production exceeding 16,000 bbl per day in early December at an ISOR of 2.0 and averaging 15,098 bbl per day at an ISOR of 2.1 from activities in the month.
Conventional Oil and Gas
Pengrowth’s significant conventional oil and gas portfolio includes a large, contiguous land base in the Greater Olds/Garrington area, encompassing over 480 gross (221 net) sections of land, with opportunities in the Cardium, Viking and Mannville sands as well as in the Mississippian carbonate section. The existing, extensive gathering and processing infrastructure provides an efficient platform for continued development in this area. Pengrowth also controls large light oil accumulations in the Swan Hills area of northern Alberta with low production decline rates and strong cash flow, as well as Montney natural gas opportunities with significant liquid yields in north eastern British Columbia.
Conventional development was curtailed in early 2015 in response to the lower commodity price environment, with activities primarily focused on safety, integrity and maintenance, as well as enhancement programs. The Company did spend $42.2 million on development activities, primarily in the first quarter of 2015, on drilling and completion of wells in the Olds/Garrington, which were completed and brought on production.
Capital Expenditures
In light of the rapid decline in commodity prices, Pengrowth adopted a conservative capital program for 2015 that contemplated very little development capital and was primarily focused on safety, integrity and maintenance activities. Fourth quarter capital expenditures were $19.1 million, with approximately 33 percent of capital spent at Lindbergh and 62 percent was spent on turnaround, maintenance and enhancement activities. The remaining five percent was spent on Pengrowth’s conventional properties.
Pengrowth’s full year 2015 capital spending amounted to $183.8 million, which represented a decrease of 80 percent compared to 2014 capital spending. Approximately 47 percent of the capital was invested at Lindbergh and 23 percent on drilling, completions and facilities at Pengrowth’s conventional properties. The remaining 30 percent of capital was invested on safety, integrity and maintenance at Pengrowth’s conventional properties, land and seismic.
Operating Expenses
Fourth quarter 2015 operating expenses of $81.4 million ($13.02 per boe) decreased $9.6 million or 11 percent compared to $91.0 million ($13.32 per boe) in the third quarter of 2015. The absence of operating expenses related to divested properties combined with a favourable prior period processing fee throughput adjustment in the fourth quarter of 2015 were the drivers behind the lower operating costs. On a per boe basis, fourth quarter operating expenses decreased $0.30 per boe compared to the third quarter of 2015 primarily due to lower costs, as described above, partly offset by lower production volumes.
Full year 2015 operating expenses of $372.1 million ($14.28 per boe) decreased $43.3 million or 10 percent compared to $415.4 million ($15.53 per boe) in 2014. Ongoing cost control efforts coupled with lower utility costs, the absence of expenses related to property dispositions, favourable prior period processing fee throughput adjustment and uneconomic shut-in volumes were the drivers leading to the year over year decline. This decline was partially offset by the inclusion of Lindbergh Phase 1 operating expenses in the results starting April 1, 2015. On a per boe basis, full year 2015 operating expenses decreased $1.25 per boe compared to the same period last year mostly due to the impact of lower costs noted above and inclusion of Lindbergh Phase 1 operating expenses of $10.55 per boe, which are lower than overall per boe operating expenses.
General and Administrative Expenses
Cash general and administrative (G&A) expenses in the fourth quarter 2015 were $15.8 million ($2.53 per boe) compared to $24.2 million ($3.54 per boe) in the third quarter of 2015. The absence of $4.8 million of severance costs incurred in the third quarter as well as lower personnel costs resulting from a 25 percent reduction in head office staff were the primary drivers behind the decline. On a per boe basis, cash G&A costs declined $1.01 per boe compared to the third quarter primarily due to the reasons listed above.
Full year 2015 cash G&A expenses of $87.0 million ($3.34 per boe) were $2.7 million higher compared to $84.3 million ($3.15 per boe) in 2014. The slight increase year over year was driven by both severance costs incurred and lower recoveries in 2015. This was partially offset by lower personnel costs resulting from 2015 staff reductions combined with lower information technology (IT) costs.
Impairments and Goodwill
As a result of the continued weakness in oil and natural gas prices, and the weaker outlook for prices, Pengrowth wrote down the book value of property, plant and equipment by $401.0 million and eliminated remaining goodwill of $117.5 million for the quarter ended December 31, 2015. These non-cash charges did not affect the Company’s cash flows. Additional details regarding the impairment charges are available in the Management’s Discussion and Analysis (MD&A) accompanying Pengrowth’s 2015 year end consolidated financial statements (Annual Financial Statements).
Adjusted Net Income (Loss)
Pengrowth recorded an adjusted net loss of $463.4 million ($0.85 per share) in the fourth quarter of 2015 primarily resulting from a non-cash impairment charge of $518.5 million (approximately $414 million after-tax) that was recognized in the quarter. For the full year, Pengrowth recorded an adjusted net loss of $811.4 million ($1.50 per share) due to non-cash impairment charges totalling $1,000.5 million (approximately $789 million after-tax) throughout the year.
Summary of Reserves Results
- Pengrowth replaced 145 percent of 2015 total production, with 37.8 millions of barrels of oil equivalent (MMboe) of 2P reserves additions in 2015, net of 35.9 MMboe of dispositions and before production. Before dispositions, the replacement was 282 percent of 2015 total production.
- 2015 total 2P reserves increased two percent to approximately 569.1 MMboe compared to 557.4 MMboe at year end 2014. Total proved reserves (1P) at 2015 year end decreased 19 percent to approximately 252.1 MMboe from 310.1 MMboe at year end 2014.
- 2P reserve life index (RLI) increased to 25.2 years at year end 2015, a 29 percent increase from the year end 2014 RLI of 19.8 years, due primarily to increased 2P reserves at Lindbergh and Groundbirch.
- 2015 F&D costs were $7.12 per boe including changes in FDC for 2P reserves. The 2015 F&D costs, excluding changes to FDC, were $2.47 per boe for 2P reserves.
- Pengrowth’s three year weighted average finding, development and acquisition (FD&A) and F&D costs for 2P reserves were $18.91 per boe and $17.78 per boe, respectively, including FDC ($3.70 per boe and $7.07 per boe, respectively, excluding FDC).
Pengrowth’s reserves and present values at year end 2015 were based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd. (GLJ) with an effective date of December 31, 2015. The values reported use GLJ’s January 1, 2016 price forecast and were prepared in accordance with National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH) and presented in GLJ’s report dated February 23, 2016. Reserves included herein are stated on a Company interest basis unless noted otherwise. In addition to the information disclosed in this news release, more detailed information is included in Pengrowth’s Annual Information Form (AIF) dated February 24, 2016, which is available on SEDAR at www.SEDAR.com and on EDGAR at www.sec.gov/edgar.shtml.
Table 1. Company Interest Reserves Summary* | |||||||
As at December 31, 2015 | |||||||
Light & Medium crude oil (Mbbl) | Heavy crude oil (Mbbl) | Bitumen (Mbbl) | Natural Gas Liquids (Mbbl) | Natural Gas (Bcf)** |
Total oil equivalent (Mboe) | Percent of 2P oil equivalent | |
Proved Developed Producing | 39,975 | 2,092 | 21,147 | 18,592 | 331.9 | 137,117 | 24% |
Proved Developed Non-producing | 1,339 | – | – | 390 | 16.3 | 4,443 | 1% |
Proved Undeveloped | 6,418 | 1,512 | 82,204 | 1,277 | 114.5 | 110,501 | 19% |
Total Proved | 47,732 | 3,604 | 103,351 | 20,259 | 462.7 | 252,060 | 44% |
Total Probable | 20,778 | 6,194 | 160,046 | 8,218 | 731.0 | 317,066 | 56% |
Total Proved Plus Probable | 68,510 | 9,798 | 263,396 | 28,477 | 1,193.7 | 569,126 | 100% |
* Numbers in table may not add due to rounding |
** Natural gas figures are an aggregate of various product types |
Reserves Reconciliation
Total 2P reserves increased approximately two percent in 2015 through the addition of 11.8 MMboe, primarily due to drilling additions and positive technical revisions, offset by production, dispositions and reductions due to economic factors. The net additional 2P reserves before production represented a replacement of 145 percent of 2015 production. The most significant of these additions were reserves attributed to the Lindbergh thermal project and the Groundbirch Montney property where 2P reserves increased by 20.1 MMboe and 77.5 MMboe, respectively in 2015 over year end 2014 numbers.
On a 1P basis, year end 2015 reserves decreased by 58.0 MMboe or 19 percent to 252 MMboe as at December 31, 2015 compared to 310 MMboe at December 31, 2014. In total, 17.5 MMboe of 1P reserves were added through drilling and revisions, offset by 49.4 MMboe of 1P reserves lost to dispositions and economic factors.
Table 2. Company Interest Reserves Reconciliation 2015* | ||||||
Light & Medium crude oil (Mbbl) | Heavy crude oil (Mbbl) | Bitumen (Mbbl) | Natural Gas Liquids (Mbbl) | Natural Gas (Bcf)** |
Total oil equivalent (Mboe) | |
Total Proved | ||||||
December 31, 2014 | 64,331 | 18,224 | 103,848 | 24,279 | 596.2 | 310,051 |
Technical Revisions | (1,001) | 463 | 3,293 | 1,177 | 41.6 | 10,868 |
Economic Factors | (10,424) | (54) | – | (1,661) | (67.9) | (23,457) |
Drilling | 1,072 | – | – | 645 | 28.4 | 6,449 |
Improved Recovery | – | – | – | – | 0.1 | 9 |
Acquisitions | 78 | – | – | 21 | 0.3 | 143 |
Dispositions | (363) | (13,011) | – | (1,055) | (69.1) | (25,938) |
Production | (5,960) | (2,019) | (3,790) | (3,146) | (66.9) | (26,064) |
December 31, 2015 | 47,732 | 3,604 | 103,351 | 20,259 | 462.7 | 252,060 |
Total Proved Plus Probable | ||||||
December 31, 2014 | 91,696 | 29,272 | 243,338 | 34,261 | 952.7 | 557,350 |
Technical Revisions | (2,862) | 737 | 4,663 | 394 | 100.7 | 19,707 |
Economic Factors | (15,814) | (128) | – | (2,647) | (94.0) | (34,251) |
Drilling | 1,811 | – | 19,185 | 1,167 | 396.0 | 88,169 |
Improved Recovery | – | – | – | – | 0.1 | 11 |
Acquisitions | 109 | – | – | 28 | 0.4 | 197 |
Dispositions | (470) | (18,064) | – | (1,581) | (95.3) | (35,993) |
Production | (5,960) | (2,019) | (3,790) | (3,146) | (66.9) | (26,064) |
December 31, 2015 | 68,510 | 9,798 | 263,396 | 28,477 | 1,193.7 | 569,126 |
* Numbers in table may not add due to rounding |
** Natural gas figures are an aggregate of various product types |
Table 3. Select prices from GLJ’s January 1, 2016 forecast prices and inflation rates | |||||
Year | WTI Crude Oil ($US/bbl) | Edm Light Crude Oil ($Cdn/bbl) | WCS Crude Oil ($Cdn/bbl) | Natural Gas at AECO ($Cdn/MMBtu) |
Inflation Rate (%/year) |
2015 Actual | 48.82 | 57.23 | 44.85 | 2.70 | 2.0 |
2016 | 44.00 | 55.86 | 42.26 | 2.76 | 2.0 |
2017 | 52.00 | 64.00 | 51.20 | 3.27 | 2.0 |
2018 | 58.00 | 68.39 | 55.39 | 3.45 | 2.0 |
2019 | 64.00 | 73.75 | 60.84 | 3.63 | 2.0 |
2020 | 70.00 | 78.79 | 66.18 | 3.81 | 2.0 |
2021 | 75.00 | 82.35 | 70.00 | 3.90 | 2.0 |
2022 | 80.00 | 88.24 | 75.88 | 4.10 | 2.0 |
2023 | 85.00 | 94.12 | 81.41 | 4.30 | 2.0 |
2024 | 87.88 | 96.48 | 84.90 | 4.50 | 2.0 |
2025 | 89.63 | 98.41 | 86.60 | 4.60 | 2.0 |
Thereafter | +2.0 %/yr | +2.0 %/yr | +2.0 %/yr | +2.0 %/yr | 2.0 |
Table 4. Before Income Tax Net Present Value Summary | ||||||
As at December 31, 2015 | ||||||
Discounted at | Percent of 2P | |||||
($ millions, except percentages) | Undiscounted | 5% | 10% | 15% | 20% | Discounted at 10% |
Proved Developed Producing | 1,605 | 1,312 | 1,096 | 939 | 822 | 34% |
Proved Developed Non-producing | 54 | 40 | 30 | 23 | 18 | 1% |
Proved Undeveloped | 2,283 | 1,210 | 678 | 394 | 232 | 21% |
Total Proved | 3,941 | 2,563 | 1,804 | 1,356 | 1,072 | 55% |
Total Probable | 6,315 | 2,902 | 1,465 | 774 | 408 | 45% |
Total Proved Plus Probable | 10,256 | 5,465 | 3,268 | 2,130 | 1,481 | 100% |
Net Asset Value
The following table provides a calculation of Pengrowth’s estimated NAV based on the estimated future net revenues associated with Pengrowth’s 2P reserves. Pengrowth calculates NAV to measure its performance. NAV is not necessarily calculated in the same manner by all issuers. Accordingly, it should not be used to make comparisons amongst different issuers.
Table 5. Net Asset Value – Before Income Tax | ||||
As at December 31, 2015 | ||||
($ millions, except percentages and share numbers) | Discounted at 5% | Discounted at 10% | ||
Value of total proved plus probable reserves(1) | 5,465 | 3,268 | ||
Undeveloped Land(2) | 148 | 148 | ||
Long-term debt, including convertible debentures and working capital(3) | (1,678 | ) | (1,678 | ) |
Reclamation funds(4) | 89 | 89 | ||
Other assets/liabilities (asset retirement obligations, commodity contracts)(3)(5) | 193 | 210 | ||
Net Asset Value | 4,216 | 2,037 | ||
Shares outstanding (millions) | 543 | 543 | ||
NAV per share ($ per share) | 7.77 | 3.75 |
(1) | Discounted net present value of GLJ total proved plus probable reserves. |
(2) | Internal undeveloped land value estimate. |
(3) | Based on estimated fair value of long-term debt. See the Annual Financial Statements. |
(4) | Pre-paid reclamation costs for Sable Offshore Energy Project, Nova Scotia and Judy Creek, Alberta. |
(5) | Internal estimated fair value of commodity contracts and other liabilities. |
As of December 31, 2015, Pengrowth’s estimated NAV, discounted at 10 percent, was $3.75 per share, which represents an approximate 49 percent decrease from the 2014 year end estimated NAV of $7.32 per share. The decline in NAV year over year is primarily attributable to a lower reserve value resulting from lower commodity prices.
Finding, Development and Acquisition Costs
During 2015, Pengrowth adopted a conservative capital budget, spending $181.8 million, excluding IT and other capital. The 2015 capital budget was focused on safety, integrity and maintenance programs, optimization and enhancement activities at Lindbergh and a limited amount of conventional development capital. A summary of the Company’s 2015 F&D and FD&A costs is provided below. These are determined separately for exploration and development activities, acquisition and disposition transactions, and with and without the change in FDC. FDC reflects the amount of estimated capital that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of future development costs will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. In addition to F&D costs, Pengrowth also reports FD&A costs because it believes that acquisitions and dispositions can have a significant impact on its ongoing reserve replacement costs. F&D costs and FD&A costs are not necessarily calculated in the same manner by all issuers. Accordingly, they should not be used to make comparisons amongst different issuers.
Table 6. 2015 F&D and FD&A Costs | |||||||||
2013 – 2015 | |||||||||
2015 | 2014 | Total/Weighted Average | |||||||
Proved plus | Proved plus | Proved plus | |||||||
Proved | Probable | Proved | Probable | Proved | Probable | ||||
FD&A Costs Excluding Future Development Capital | |||||||||
Exploration and development capital expenditures – $millions | 181.8 | 181.8 | 902.5 | 902.5 | 1776.7 | 1776.7 | |||
Exploration and Development Reserve Additions including Revisions – MMboe | (6.1) | 73.6 | 32.9 | 112.4 | 110.2 | 251.3 | |||
Finding and Development Cost – $/boe1,4 | (29.80) | 2.47 | 27.43 | 8.03 | 16.12 | 7.07 | |||
F&D Recycle Ratio, $/$ | (0.8) | 10.1 | 0.9 | 3.2 | 1.5 | 3.5 | |||
Net Acquisition (Disposition) Capital – $millions | (209.6) | (209.6) | (67.5) | (67.5) | (1,254.9) | (1,254.9) | |||
Net Acquisition (Disposition) Reserve Additions – MMboe | (25.8) | (35.8) | (3.1) | (5.6) | (74.5) | (110.4) | |||
Net Acquisition Cost – $/boe | 8.12 | 5.85 | 21.77 | 12.05 | 16.84 | 11.37 | |||
Total Capital Expenditures including Net Acquisitions (Dispositions) – $millions | (27.8) | (27.8) | 835.0 | 835.0 | 521.8 | 521.8 | |||
Reserve Additions including Net Acquisitions (Dispositions) – MMboe | (31.9) | 37.8 | 29.8 | 106.8 | 35.7 | 140.9 | |||
Finding Development and Acquisition Cost – $/boe2 | 0.87 | (0.74) | 28.02 | 7.82 | 14.62 | 3.70 | |||
FD&A Costs Including Future Development Capital | |||||||||
Exploration and Development Capital Expenditures – $millions | 181.8 | 181.8 | 902.5 | 902.5 | 1,776.7 | 1,776.7 | |||
Exploration and Development Change in FDC – $millions | (239.7) | 341.9 | (51.7) | 1,607.2 | 740.3 | 2,690.3 | |||
Exploration and Development Capital including Change in FDC – $millions | (57.9) | 523.7 | 850.8 | 2,509.7 | 2,517.0 | 4,467.0 | |||
Exploration and Development Reserve Additions including Revisions – MMboe | (6.1) | 73.6 | 32.9 | 112.4 | 110.2 | 251.3 | |||
Finding and Development Cost – $/boe1,4 | 9.49 | 7.12 | 25.86 | 22.33 | 22.84 | 17.78 | |||
F&D Recycle Ratio, $/$ | 2.6 | 3.5 | 1.0 | 1.1 | 1.1 | 1.4 | |||
Net Acquisition (Disposition) Capital – $millions | (209.6) | (209.6) | (67.5) | (67.5) | (1,254.9) | (1,254.9) | |||
Net Acquisition (Disposition) Change in FDC – $millions | (107.3) | (133.9) | (5.3) | (32.2) | (337.3) | (547.3) | |||
Net Acquisition (Disposition) Capital including Change in FDC – $millions | (316.9) | (343.5) | (72.8) | (99.7) | (1,592.2) | (1,802.2) | |||
Net Acquisition (Disposition) Reserve Additions – MMboe | (25.8) | (35.8) | (3.1) | (5.6) | (74.5) | (110.4) | |||
Net Acquisition (Disposition) Cost – $/boe | 12.28 | 9.59 | 23.48 | 17.80 | 21.37 | 16.32 | |||
Total Capital Expenditures including Net Acquisitions (Dispositions) – $millions | (27.8) | (27.8) | 835.0 | 835.0 | 521.8 | 521.8 | |||
Total Change in FDC – $millions | (347.0) | 208.0 | (57.0) | 1,575.0 | 403.0 | 2,143.0 | |||
Total Capital including Change in FDC – $millions | (374.8) | 180.2 | 778.0 | 2,410.0 | 924.8 | 2,664.8 | |||
Reserve Additions including Net Acquisitions (Dispositions) – MMboe | (31.9) | 37.8 | 29.8 | 106.8 | 35.7 | 140.9 | |||
Finding Development and Acquisition Cost including FDC – $/boe | 11.75 | 4.77 | 26.11 | 22.57 | 25.90 | 18.91 |
2013 – 2015 | ||||||||
2015 | 2014 | Weighted Average | ||||||
Operating Netback ($/boe) (3) | 24.97 | 25.64 | 24.95 |
(1) | The negative 2015 F&D cost excluding FDC for proved reserves is due to overall negative reserve change resulting from additions, revisions and economic factors. |
(2) | The negative 2015 FD&A cost excluding FDC for 2P reserves is due to proceeds from dispositions exceeding capital expenditures plus acquisition costs. |
(3) | The operating netbacks are equal to sales revenue plus other income less royalties, operating expenses and transportation costs. Please see the MD&A and AIF for further information. |
(4) | 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 |
Table 7. Total Future Net Revenue (Undiscounted) | ||||||||
As at December 31, 2015 | ||||||||
($ millions) | Revenue | Royalties | Operating Costs | Development Costs | Abandonment and Reclamation Costs1 |
Revenue Before Income Tax | Income Tax2 | Revenue After Income Tax |
Proved Developed Producing | 6,923 | 963 | 3,630 | 142 | 583 | 1,605 | – | 1,605 |
Proved Developed Non-producing | 217 | 34 | 111 | 8 | 11 | 54 | – | 54 |
Proved Undeveloped | 7,432 | 1,172 | 2,441 | 1,447 | 89 | 2,283 | 151 | 2,132 |
Total Proved | 14,572 | 2,168 | 6,182 | 1,597 | 683 | 3,941 | 151 | 3,790 |
Total Probable | 19,547 | 3,607 | 5,816 | 3,568 | 242 | 6,315 | 2,037 | 4,278 |
Total Proved Plus Probable | 34,119 | 5,775 | 11,998 | 5,165 | 925 | 10,256 | 2,188 | 8,068 |
(1) | Includes GLJ’s forecast of well abandonment and reclamation costs, abandonment and reclamation costs for the Lindbergh central processing facilities and abandonment costs for Sable Island facilities and subsea pipelines, based on estimates provided by Pengrowth but does not include abandonment costs for other facilities or any surface reclamation costs. Please see the AIF for further information. |
(2) | Income tax values were calculated by Pengrowth using GLJ’s before tax cash flow, current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. Please see the AIF for further information. |
Reserve Life Index
Pengrowth’s 2015 proved RLI increased approximately three percent to 12.1 years from 11.7 years in 2014. The RLI for proved plus probable reserves increased to 25.2 years, a 29 percent increase from year end 2014 RLI of 19.8 years.
Table 8. Historical Reserve Life Index | |||||
Reserve Life Index (Years) | 2015 | 2014 | 2013 | 2012 | 2011 |
Proved Developed Producing | 6.5 | 7.2 | 7.4 | 7.6 | 7.6 |
Total Proved | 12.1 | 11.7 | 11.8 | 9.2 | 9.0 |
Total Proved Plus Probable | 25.2 | 19.8 | 17.4 | 14.7 | 12.0 |
RLI refers to the number of years determined by dividing Pengrowth’s company interest in a category of reserves by the next year’s forecast company interest production for the corresponding reserve category. The reserves and next year’s forecast production come from the GLJ Report. Pengrowth uses RLI as a comparative measure of the longevity of its reserves. RLIs are not necessarily comparative as between different issuers as there is some variation in calculation methodology.
Reserves and Contingent Resources Classification
The following table summarizes GLJ’s estimates of reserves and contingent resources, as of year end 2015, for the Lindbergh thermal property and Groundbirch natural gas property. The contingent resources are sub-classified according to project maturity and risked for chance of development.
Table 9. Summary of Reserves and Contingent Resources | ||||||||||
As at December 31, 2015 | ||||||||||
Reserves | Risked1Contingent Resources | |||||||||
Field | Proved | Proved + Probable | Proved + Probable + Possible | Project Maturity Sub-Class |
Low Estimate | Best Estimate | High Estimate | |||
Lindbergh (MMbbl) | 103.4 | 263.4 | 370.6 | Development Pending | 15.4 | 62.6 | 95.3 | |||
Development Unclarified | 18.4 | 36.7 | 54.4 | |||||||
Groundbirch (Bcf) | 120.9 | 693.1 | 843.9 | Development Pending | 108.9 | 180.2 | 249.0 | |||
Development Unclarified | 133.8 | 476.7 | 639.8 |
(1) | Risked for chance of development |
The reserves attributed to Lindbergh increased in 2015 due to ongoing reservoir delineation and revised mapping. Contingent resources also increased as a result of assigning increased recoveries due to infill drilling between existing and future SAGD well pairs. This was offset somewhat by reclassifying a portion of the contingent resources as reserves. The contingencies which prevent the remaining contingent resources from being classified as reserves at Lindbergh include: the need for additional evaluation well drilling within the area, regulatory approval of the first expansion phase to 30,000 bbl per day, firm development plans beyond the initial expansion phase, high quality project design and cost estimates and commitment by Pengrowth for future development.
Reserves at Groundbirch increased in 2015 primarily due to area activity allowing Pengrowth to reclassify a portion of what was previously classified as contingent resources as reserves and increasing recovery based on improved performance from advances in fracturing techniques. Contingent resources increased due to the higher recovery per well and assigning additional resources to vertical development in the thick Montney section. The Groundbirch tight gas resource is in early stage evaluation and development. Additional drilling, completion and testing data is required for planning and design purposes with respect to well spacing, pipeline and facility capacity and scheduling of further development. The reclassification of these contingent resources as reserves is contingent upon creating a development plan with corporate approval and commitment to proceed within an acceptable time period.
Financial Flexibility and Liquidity
Pengrowth is committed to ensuring its financial flexibility in 2016. Pengrowth’s $1.0 billion committed revolving credit facility, was renewed and extended in 2015 and now has a maturity date of March 31, 2019. The Company has no scheduled debt maturities in 2016 and expects to be in a position to materially reduce its outstanding debt through a combination of funds flow from operations supported by a substantial hedging program, disposition proceeds, and its ongoing cost reduction initiatives in 2016.
Approximately 87 percent of Pengrowth’s long-term debt is comprised of senior unsecured term debt with fixed interest rates and maturity dates. At December 31, 2015 total debt before working capital decreased $13.4 million to $1,857 million compared to $1,870 million at December 31, 2014. As the majority of Pengrowth’s debt is denominated in U.S. dollars and U.K. pound sterling, the weakening of the Canadian dollar relative to these currencies since December 31, 2014 drove the total debt before working capital balance up by approximately $265 million year over year. This was, however, more than offset by debt repayments of approximately $280 million in 2015 through a combination of proceeds from the 2015 divestment activities and funds flow from operations.
Commodity Risk Management
Pengrowth has extensive oil and natural gas hedges in place through the end of 2016 that are expected to provide a significant degree of cash flow certainty notwithstanding the current low commodity price environment. Currently, the Company has approximately 22,239 bbl per day of 2016 crude oil production (74 percent of 2016 estimated oil production) hedged at Cdn $88.57 per bbl and approximately 127 million cubic feet per day (MMcf per day) of 2016 natural gas production (93 percent of 2016 estimated gas production) hedged at Cdn $3.28 per Mcf. The Company also has significant natural gas hedges in place for 2017 and 2018 and continues to target opportunities to add additional crude oil hedges for 2017 and 2018 should the commodity price opportunity present itself. The mark to market value of Pengrowth’s hedge book, including foreign exchange hedges was approximately $599 million as at February 19, 2016.
A summary of Pengrowth’s commodity risk management contracts in place as at January 31, 2016 is provided in the table below. A complete listing of all risk management contracts in place is available in the MD&A.
Table 10. Summary of Commodity Risk Management Contracts | ||
Volume | Average Price | |
Crude Oil (bbl per day) | ($Cdn/bbl) | |
2016 | 22,239 | $88.57 |
2017 | 5,000 | $79.19 |
2018 | 5,500 | $80.49 |
Natural Gas (MMcf per day) | ($Cdn/Mcf) | |
2016 | 126.8 | $3.28 |
2017 | 90.6 | $3.47 |
2018 | 66.3 | $3.59 |
2019 | 2.4 | $3.52 |
2016 Capital Plan
Pengrowth’s 2016 capital program has no capital allocated for drilling but will allocate some minor capital to advance long-term projects, namely at Lindbergh and Bernadet, as these projects represent excellent low cost opportunities for longer-term production growth. The bulk of Pengrowth’s 2016 capital program will be earmarked for safety, asset integrity and maintenance programs.
The 2016 capital budget was conservatively based on the assumption of an average WTI crude oil price of US $30.00 per bbl, an AECO natural gas price of Cdn $2.40 per Mcf, WTI/WCS heavy oil differential of US$12.60 per bbl and a $0.70 US/Cdn exchange rate.
2016 Forecast Guidance Summary
The following is a summary of Pengrowth’s 2016 guidance and does not reflect any anticipated acquisition or divestment activity. Certain guidance estimates may fluctuate with changes in commodity prices.
Average daily production volume (boe per day) | 59,000 to 61,000 |
Total capital expenditures ($ millions) | 60 to 70 |
Royalties1 (% of sales) | 7 to 8 |
Net operating costs ($ per boe)2 | 15.25 to 16.25 |
Cash G & A expense ($ per boe)2 | 2.75 to 3.25 |
(1) | Royalties are before impacts of commodity risk management activities |
(2) | Per boe estimates based on high and low ends of production guidance |
(3) | Guidance based on US $30.00/bbl, an AECO natural gas price of Cdn $2.40/Mcf, WTI/WCS heavy oil differential of US$12.60/bbl and a $0.70 US/Cdn exchange rate. |
Outlook
Debt Repayment Strategy
Pengrowth is committed to ensuring its financial flexibility in 2016 and expects to direct all excess cash flow from its hedging program, disposition proceeds, and funds flow from operations towards reducing its outstanding debt position.
NYSE Continued Listing Standard Notification
With respect to the previously announced notice from the NYSE that was received on October 29, 2015, the trading price of Pengrowth’s shares fell below the minimum trading price of US$1.00 for a consecutive 30 trading-day period on that exchange. The effect of this is that the shares will be delisted from that exchange if the share price does not recover by the end of April or if the Company does not complete a plan to resolve this issue, such as a share consolidation. The Company’s current intention is to not consolidate the shares to resolve this issue.
Given the current volatile market environment, the debt reduction, property development and disposition initiatives being pursued by the Company coupled with the belief that commodity prices will increase at some point in the future, Pengrowth is inclined to wait until the market and commodity prices stabilize to see if the share price recovers on its own.
Pengrowth can regain compliance with the NYSE minimum standard if, prior to April 30, 2016, on the last trading day of any calendar month, Pengrowth’s common shares have a closing price of at least US$1.00 per share and a 30 trading-day average closing price of at least US$1.00 per share. Management of Pengrowth continues to actively monitor the share price and evaluate all available options in order to regain compliance with the NYSE’s price listing standard. However, failure to meet the standard in this time period is expected to result in shares being delisted from the NYSE shortly following the end of April 2016. This delisting will not affect the continued listing and trading of Pengrowth’s shares on the TSX. If the shares are delisted, the Company may, in the future, consider applying for a new listing on the NYSE if and when the share price stabilizes above the NYSE minimum requirements.
Pengrowth’s audited Annual Financial Statements and related MD&A, as well as Pengrowth’s 40-F containing the AIF dated February 24, 2016, can be viewed on Pengrowth’s website at www.pengrowth.com. They are also available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.shtml. Hard copies of Pengrowth’s complete Annual Report can also be requested free of charge by contacting Pengrowth Investor Relations at
investorrelations@pengrowth.com.
Conference call:
Pengrowth will host a conference call and listen only audio webcast beginning at 6:30 A.M. Mountain Time (MT) on Thursday, February 25, during which management will review Pengrowth’s results and respond to questions from the analyst community.
To ensure timely participation in the teleconference, callers are encouraged to dial in 10 minutes prior to the start of the call to register.
Dial-in numbers:
Toll free: (800) 355-4959 or Toronto local (416) 340-8527
Live listen only audio webcast: http://www.gowebcasting.com/7288
About Pengrowth:
Pengrowth Energy Corporation is an intermediate Canadian producer of oil and natural gas, headquartered in Calgary, Alberta. Pengrowth’s assets include the Lindbergh thermal oil, Cardium light oil, Swan Hills light oil and the Groundbirch and Bernadet Montney gas projects. Pengrowth’s shares trade on both the Toronto Stock Exchange under the symbol “PGF” and on the New York Stock Exchange under the symbol “PGH”.