CALGARY, ALBERTA -- (Marketwired) -- 02/24/16 -- 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 Dec 31, Dec 31, Change Dec 31, Dec 31, Change
amounts) 2015 2014 (3) 2015 2014 (3)
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PRODUCTION
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Average daily
production
(boe/d) 67,934 71,802 (5) 71,409 73,288 (3)
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FINANCIAL
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Funds flow from
operations (1)
(2) $ 114.2 $ 115.8 (1) $ 459.3 $ 505.7 (9)
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Funds flow from
operations per
share (1) (2) $ 0.21 $ 0.22 (5) $ 0.85 $ 0.96 (11)
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Oil and gas sales $ 169.1 $ 291.5 (42) $ 830.8 $ 1,496.9 (44)
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Oil and gas sales
per boe $ 27.06 $ 44.13 (39) $ 31.88 $ 55.96 (43)
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Realized
commodity risk
management gains
(losses) $ 97.7 $ 21.7 350 $ 327.0 $ (96.1) (440)
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Realized
commodity risk
management gains
(losses) per boe $ 15.63 $ 3.29 375 $ 12.55 $ (3.60) (449)
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Operating
expenses $ 81.4 $ 94.5 (14) $ 372.1 $ 415.4 (10)
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Operating
expenses per boe $ 13.02 $ 14.31 (9) $ 14.28 $ 15.53 (8)
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Royalty expenses $ 19.1 $ 51.2 (63) $ 89.5 $ 268.6 (67)
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Royalty expenses
per boe $ 3.06 $ 7.75 (61) $ 3.43 $ 10.04 (66)
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Royalty expenses
as a percent of
sales 11.3% 17.6% 10.8% 17.9%
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Operating netback
per boe (1) $ 25.07 $ 24.04 4 $ 24.97 $ 25.64 (3)
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Cash G&A expenses
(1) $ 15.8 $ 21.2 (25) $ 87.0 $ 84.3 3
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Cash G&A expenses
per boe (1) $ 2.53 $ 3.21 (21) $ 3.34 $ 3.15 6
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Capital
expenditures $ 19.1 $ 258.8 (93) $ 183.8 $ 904.0 (80)
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Net cash
dispositions (3) $ (183.4) $ (19.8) $ (209.6) $ (67.5) 211
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Dividends paid $ 5.5 $ 63.8 (91) $ 122.3 $ 253.2 (52)
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Dividends paid
per share $ 0.01 $ 0.12 (92) $ 0.23 $ 0.48 (52)
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Number of shares
outstanding at
period end
(000's) 543,033 533,438 2 543,033 533,438 2
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Weighted average
number of shares
outstanding
(000's) 543,033 531,654 2 539,951 527,851 2
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STATEMENT OF
INCOME (LOSS)
---------------------------------------------------------------------
Adjusted net
income (loss)
(1) $ (463.4) $ (854.8) (46) $ (811.4) $ (879.0) (8)
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Net income (loss) $ (468.6) $ (506.0) (7) $(1,093.1) $ (578.8) 89
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Net income (loss)
per share $ (0.86) $ (0.95) (9) $ (2.02) $ (1.10) 84
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DEBT (4)
----------------------------------------------------------------------------
Senior debt $ 1,719.5 $ 1,722.0 -
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Convertible
debentures $ 137.0 $ 137.2 -
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Total debt before
working capital $ 1,856.5 $ 1,859.2 -
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Total debt
including
working capital $ 1,671.2 $ 1,836.5 (9)
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CONTRIBUTION
BASED ON
OPERATING
NETBACKS (1)
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Light oil 52% 50% 54% 55%
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Heavy oil 42% 17% 37% 17%
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Natural gas
liquids 4% 11% 2% 11%
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Natural gas 2% 22% 7% 17%
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PROVED PLUS
PROBABLE
RESERVES
----------------------------------------------------------------------------
Light oil (Mbbls) 68,510 91,695 (25)
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Heavy oil (Mbbls) 273,194 272,610 -
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Natural gas
liquids (Mbbls) 28,477 34,261 (17)
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Natural gas (Bcf) 1,194 953 25
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Total oil
equivalent
(Mboe) 569,126 557,350 2
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CAPITAL
PERFORMANCE (1)
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Finding &
Development
("F&D") cost per
boe (1)(5) $ 7.12 $ 22.33 (68)
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Recycle ratio
(1)(6) 3.5 1.1 218
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(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(i)
As at December 31, 2015
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Light &
Medium Heavy Natural
crude crude Gas Natural Total oil Percent of
oil oil Bitumen Liquids Gas equivalent 2P oil
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Bcf)(ii) (Mboe) equivalent
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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%
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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%
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Total Proved
Plus
Probable 68,510 9,798 263,396 28,477 1,193.7 569,126 100%
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(i) Numbers in table may not add due to rounding
(ii) 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(i)
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Light & Natural
Medium Heavy Gas Natural Total oil
crude oil crude oil Bitumen Liquids Gas equivalent
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Bcf)(ii) (Mboe)
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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)
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December 31,
2015 47,732 3,604 103,351 20,259 462.7 252,060
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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)
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December 31,
2015 68,510 9,798 263,396 28,477 1,193.7 569,126
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(i) Numbers in table may not add due to rounding
(ii) 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
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WTI Crude Edm Light WCS Crude Natural Gas Inflation
Oil Crude Oil Oil at AECO Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu) (%/year)
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2015 Actual 48.82 57.23 44.85 2.70 2.0
2016 44.00 55.86 42.26 2.76 2.0
2017 52.00 64.00 51.20 3.27 2.0
2018 58.00 68.39 55.39 3.45 2.0
2019 64.00 73.75 60.84 3.63 2.0
2020 70.00 78.79 66.18 3.81 2.0
2021 75.00 82.35 70.00 3.90 2.0
2022 80.00 88.24 75.88 4.10 2.0
2023 85.00 94.12 81.41 4.30 2.0
2024 87.88 96.48 84.90 4.50 2.0
2025 89.63 98.41 86.60 4.60 2.0
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Thereafter +2.0 %/yr +2.0 %/yr +2.0 %/yr +2.0 %/yr 2.0
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Table 4. Before Income Tax Net Present Value Summary
As at December 31, 2015
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Percent of
Discounted at 2P
--------------------------------
($ millions, except Discounted
percentages) Undiscounted 5% 10% 15% 20% at 10%
----------------------------------------------------------------------------
Proved Developed 1,605 1,312 1,096 939 822 34%
Producing
Proved Developed 54 40 30 23 18 1%
Non-producing
Proved Undeveloped 2,283 1,210 678 394 232 21%
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Total Proved 3,941 2,563 1,804 1,356 1,072 55%
Total Probable 6,315 2,902 1,465 774 408 45%
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Total Proved Plus 10,256 5,465 3,268 2,130 1,481 100%
Probable
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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
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Discounted Discounted
($ millions, except percentages and share numbers) at 5% 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
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Net Asset Value 4,216 2,037
Shares outstanding (millions) 543 543
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NAV per share ($ per share) 7.77 3.75
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(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
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2013 - 2015
Total/Weighted
2015 2014 Average
----------------- ----------------- -------------------
Proved Proved Proved
plus plus 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 -
$/boe(1,4) (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 - $/boe(2) 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 -
$/boe(1,4) 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
----------------------------------------------------------------------------
Operating Development
($ millions) Revenue Royalties Costs Costs
----------------------------------------------------------------------------
Proved Developed Producing 6,923 963 3,630 142
Proved Developed Non-producing 217 34 111 8
Proved Undeveloped 7,432 1,172 2,441 1,447
----------------------------------------------------------------------------
Total Proved 14,572 2,168 6,182 1,597
Total Probable 19,547 3,607 5,816 3,568
----------------------------------------------------------------------------
Total Proved Plus Probable 34,119 5,775 11,998 5,165
----------------------------------------------------------------------------
Table 7. Total Future Net Revenue (Undiscounted)
As at December 31, 2015
----------------------------------------------------------------------------
Abandonment
and Revenue Revenue
Reclamation Before Income After
($ millions) Costs(1) Income Tax Tax(2) Income Tax
----------------------------------------------------------------------------
Proved Developed Producing 583 1,605 - 1,605
Proved Developed Non-producing 11 54 - 54
Proved Undeveloped 89 2,283 151 2,132
----------------------------------------------------------------------------
Total Proved 683 3,941 151 3,790
Total Probable 242 6,315 2,037 4,278
----------------------------------------------------------------------------
Total Proved Plus Probable 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 Risked(1)Contingent Resources
-------------------------------------------------------------------
Proved + Project
Proved + Probable + Maturity Low Best High
Field Proved Probable Possible Sub-Class Estimate Estimate Estimate
----------------------------------------------------------------------------
Lindbergh Development
(MMbbl) 103.4 263.4 370.6 Pending 15.4 62.6 95.3
Development
Unclarified 18.4 36.7 54.4
----------------------------------------------------------------------------
Groundbir Development
ch (Bcf) 120.9 693.1 843.9 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
Royalties(1) (% 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".
PENGROWTH ENERGY CORPORATION
Derek Evans, President and Chief Executive Officer
Currency:
All amounts are stated in Canadian dollars unless otherwise specified.
Caution Regarding Engineering Terms:
When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All production figures stated are based on Company Interest before the deduction of royalties.
Advisory Regarding Reserves and Contingent Resources
All reserves, reserve life index, and production information herein is based upon Pengrowth's company interest (Pengrowth's working interest share of reserves or production plus Pengrowth's royalty interest, being Pengrowth's interest in production and payment that is based on the gross production at the wellhead), before deduction of royalty obligations and using GLJ's January 1, 2016 forecast prices and costs as disclosed herein. Numbers presented may not add due to rounding.
The estimated value of reserves disclosed in this press release does not represent the fair market value of the reserves. The estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregation.
Developed Producing Reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed Non-Producing Reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
ISOR refers to the efficiency of a steam injection recovery process and is the measure of steam, in equivalent barrels of water required to produce one barrel of bitumen, currently or at any time.
Proved Developed Producing Reserves refers to those proved reserves that are developed producing reserves.
Proved Reserves refers to those reserves that can be estimated with a high degree of certainty to be recoverable; it is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Total Proved Plus Probable Reserves or 2P means the aggregate of proved reserves and probable reserves.
Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Probable Reserves refers to those additional reserves that are less certain to be recovered than Proved Reserves; it is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves.
Undeveloped Reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political and regulatory matters or lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates. Contingent Reserves do not constitute and should not be confused with reserves. There is no certainty that it will be commercially viable to produce any portion on the Contingent Resources. The estimates of Contingent Resources associated with Pengrowth's Lindbergh thermal oil property and Groundbirch gas property included herein have been evaluated by GLJ, Pengrowth's independent qualified reserves evaluator, in accordance with COGEH and NI 51-101. A best estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 50 percent confidence level. A low estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 90 percent confidence level. A high estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a ten percent confidence level. The Contingent Resources as disclosed herein are considered economic based on forecast prices and costs as at December 31, 2015. Additional information relating to the Contingent Resources estimate for Pengrowth's Lindbergh thermal oil property and Groundbirch gas property, including specific contingencies and significant positive and negative factors associated with the estimate, can be found in Pengrowth's AIF dated February 24, 2016, which can be accessed immediately on Pengrowth's website at www.pengrowth.com and has been filed on SEDAR at www.sedar.com and on Form 40-F on EDGAR at www.sec.gov/edgar.shtml.
Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.
Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).
Development Unclarified describes the status of a project where the evaluation is incomplete and there is ongoing activity to resolve any risks and uncertainties.
Caution Regarding Forward Looking Information:
This press release contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of the Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to Remaining value of unrealized foreign exchange, power and commodity price hedges; continuation of responses to low commodity prices; expectation of excess cash flow and proceeds from dispositions and the application thereof to debt reduction; estimated net asset value; estimated future net revenue; reserve life index; financial flexibility and liquidity; maturity date of credit facility; scheduled debt maturities; ability to reduce indebtedness through funds flow, hedge proceeds, disposition proceeds and ongoing cost reduction initiatives; risk management contracts; debt repayment strategy; planned normal course issuer bid for convertible debentures; plan to repay existing debentures and term notes with cash on hand and credit facilities; anticipated substantial reductions in debt service costs; investigation of ways to repurchase outstanding indebtedness; current intention regarding share consolidation and potential New York Stock Exchange delisting. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.
Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: changes in general economic, market and business conditions; the volatility of oil and gas prices; fluctuations in production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; geological, technical, drilling and processing problems and other difficulties in producing reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; fluctuations in interest rates; inadequate insurance coverage; compliance with environmental laws and regulations; actions by governmental or regulatory agencies, including changes in tax laws; the failure to qualify as a mutual fund trust; Pengrowth's ability to access external sources of debt and equity capital; the impact of foreign and domestic government programs and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Further information regarding these factors may be found under the heading "Business Risks" in the MD&A and under "Risk Factors" in the AIF.
The foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release, and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable laws.
The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.
Non-GAAP and Operational Measures
In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents additional and non-GAAP measures including adjusted net income (loss), operating netbacks, total debt before working capital, total debt including working capital, cash G&A expenses, funds flow from operations and net asset value.
Pengrowth calculates recycle ratio to measure its performance. It reflects the amount of cash flow relative to investment. To calculate the recycle ratio, Pengrowth divides annual operating netback by annual proved plus probable F&D costs including change in FDC. F&D cost per boe is determined by dividing current period reserve additions, including revisions, into the corresponding period's capital expenditures plus the change in FDC. Pengrowth uses F&D costs, both including and excluding acquisitions and dispositions, as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions.
These measures do not have any standardized meaning prescribed by GAAP and therefore are unlikely to be comparable to similar measures presented by other companies.
These measures are provided, in part, to assist readers in determining Pengrowth's ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth's ongoing business on an overall basis.
These measures should be considered in addition to, and not as a substitute for, net income (loss), cash provided by operations and other measures of financial performance and liquidity reported in accordance with IFRS. Further information with respect to these additional and non-GAAP measures can be found in the MD&A.
Note to US Readers
We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.
Current SEC reporting requirements permit, but do not require United States oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See "Presentation of our Reserve Information" in our most recent Annual Information Form or Form 40-F for more information.
We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.
Contacts:
Pengrowth
Wassem Khalil
Manager, Investor Relations
(403) 233-0224 or Toll free 1-855-336-8814
Pengrowth
Investor Relations
investorrelations@pengrowth.com
www.pengrowth.com
