Mr. Derek Evans reports
PENGROWTH DELIVERS STRONG 2014 OPERATIONAL RESULTS AND SIGNIFICANT RESERVES GROWTH
Pengrowth Energy Corp. has released its financial and operating results for the fourth quarter and the full-year 2014, as well as year-end 2014 reserve results.
Pengrowth had another strong year in 2014, delivering on its commitments, exceeding production guidance, getting Lindbergh steaming and adding to its drilling inventory in the liquids-rich Montney fairway. As commodity prices declined, Pengrowth announced extensive and pro-active measures for 2015, designed to ensure the company's financial health and sustainability in the current low-commodity-price environment. In addition to the company's extensive hedging program, these new initiatives included a significantly reduced capital program, the deferral of Lindbergh phase 2 by at least one year and a reduced dividend payout.
Operational, financial and reserves highlights for 2014:
- Pengrowth achieved fourth quarter and full-year average production of
71,802 barrels of oil equivalent per day and 73,288 boe per day,
respectively. Full-year 2014 average production exceeded the upper end
of guidance as strong production performance from Pengrowth's Cardium
development program more than offset minor asset dispositions.
- It delivered on-time construction, commissioning and first steam at the
first commercial phase of the Lindbergh thermal project.
- The company added to low-cost Montney development inventory with the acquisition of
32.6 gross/net sections of prospective liquids-rich lands adjacent to
existing lands at Bernadet in northeastern British Columbia for $123.6-million in the fourth quarter.
- Fourth quarter funds flow from operations was $115.8-million (22 cents per
share), and full-year funds flow from operations was $505.7-million
(96 cents per share). Fourth quarter funds flow included realized hedging
gains of $21.7-million.
- As at Dec. 31, 2014, the value of Pengrowth's unrealized foreign
exchange, power and commodity price hedges was $469-million.
- A non-cash, after-tax impairment charge of approximately $858-million
was recorded on mature assets in the fourth quarter, resulting in a full-year 2014 adjusted net loss of $879.0-million ($1.67 per share).
Declining commodity prices, coupled with a reduction in the price
forecast for oil and natural gas, were the main reasons for the
impairment.
- The year-end 2014 estimated net asset value per share of $7.32
remained relatively unchanged compared with the year-end 2013 estimate of
$7.52 per share.
- Pengrowth replaced 399 per cent of 2014 total production with 106.7
million boe of proved plus probable (2P) reserve additions in 2014, net of
dispositions.
- Finding and development costs for 2014 of $22.33 per boe included
changes in future development costs for 2P reserves.
- Best-estimate contingent resources at Groundbirch increased by 87
per cent to 634 billion cubic feet, and best-estimate contingent
resources at Lindbergh were approximately 101 million barrels at Dec. 31,
2014. In aggregate, the best-estimate contingent resources for
Groundbirch and Lindbergh were approximately 206 million boe.
Derek Evans, president and chief executive officer of Pengrowth, said: "We are extremely pleased with our 2014 operational results. We exceeded the top end of production guidance, driven by superior execution costs and production rates in Pengrowth's conventional assets. Lindbergh was delivered on time with first steam in December, 2014, and we added to our low-cost Montney drilling inventory with a liquids-rich land acquisition in the fourth quarter. As commodity prices declined, we significantly reduced our 2015 capital program, deferred Lindbergh phase 2 development capital and reduced the dividend by 50 per cent. We moved quickly and decisively to ensure the financial health and sustainability of Pengrowth. With cash flow stability provided by our hedge book in 2015 and 2016, executing on these measures will help ensure that Pengrowth emerges as a stronger company when commodity prices strengthen."
SUMMARY OF FINANCIAL AND OPERATING RESULTS
(monetary amounts in millions except per boe and
per share amounts)
Three months ended Twelve months ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2014 2013 2014 2013
Production
Average daily
production
(boe/d) 71,802 77,371 73,288 84,527
Financial
Funds flow from
operations $ 115.8 $ 105.9 $ 505.7 $ 560.9
Funds flow from
operations per
share $ 0.22 $ 0.20 $ 0.96 $ 1.08
Oil and gas sales $ 291.5 $ 343.7 $ 1,496.9 $ 1,593.4
Oil and gas sales
per boe $ 44.13 $ 48.29 $ 55.96 $ 51.64
Realized commodity
risk management
gains (losses) $ 21.7 $ (15.7) $ (96.1) $ (55.0)
Realized commodity
risk management
gains (losses)
per boe $ 3.29 $ (2.21) $ (3.60) $ (1.78)
Operating expenses $ 94.5 $ 109.2 $ 415.4 $ 482.5
Operating expenses
per boe $ 14.31 $ 15.34 $ 15.53 $ 15.64
Royalty expenses $ 51.2 $ 62.8 $ 268.6 $ 275.1
Royalty expenses
per boe $ 7.75 $ 8.82 $ 10.04 $ 8.92
Royalty expenses
as a per cent of
sales 17.6% 18.3% 17.9% 17.3%
Operating netback
per boe $ 24.04 $ 20.82 $ 25.64 $ 24.35
Cash G&A expense $ 21.2 $ 21.7 $ 84.3 $ 87.8
Cash G&A expenses
per boe $ 3.21 $ 3.05 $ 3.15 $ 2.85
Capital
expenditures $ 258.8 $ 239.7 $ 904.0 $ 695.8
Capital
expenditures per
share $ 0.49 $ 0.46 $ 1.71 $ 1.34
Net cash
acquisitions
(dispositions) $ (19.8) $ (29.2) $ (67.5) $ (977.7)
Net cash
acquisitions
(dispositions)
per share $ (0.04) $ (0.06) $ (0.13) $ (1.89)
Dividends paid $ 63.8 $ 62.4 $ 253.2 $ 248.1
Dividends paid per
share $ 0.12 $ 0.12 $ 0.48 $ 0.48
Statement of
income (loss)
Adjusted net
income (loss) $ (854.8) $ (37.3) $ (879.0) $ (183.8)
Net income (loss) $ (506.0) $ (91.1) $ (578.8) $ (316.9)
Net income (loss)
per share $ (0.95) $ (0.17) $ (1.10) $ (0.61)
Contribution based
on operating
netbacks
Light oil 50% 57% 55% 65%
Heavy oil 17% 16% 17% 15%
Natural gas
liquids 11% 18% 11% 12%
Natural gas 22% 9% 17% 8%
Proved plus
probable reserves
Light oil (Mbbl) 91,695 103,473
Heavy oil (Mbbl) 272,610 172,761
Natural gas
liquids (Mbbl) 34,261 35,091
Natural gas (bcf) 953 996
Total oil
equivalent (Mboe) 557,350 477,385
Capital
performance
Finding and
development cost
(F&D) per boe $ 22.33 $ 21.96
Recycle ratio 1.1 1.1
Production
Pengrowth's fourth quarter average daily production of 71,802 boe per day decreased 1 per cent compared with the third quarter of 2014, due largely to minor property dispositions, which reduced volumes by approximately 1,400 barrels of oil equivalent per day in the fourth quarter. Offsetting this was increased Sable Island natural gas production, following the completion of maintenance work in the third quarter of 2014 and strong performance from the two-well Groundbirch development program.
Full-year 2014 average production of 73,288 boe per day exceeded guidance of 71,000 to 73,000 boe per day despite the asset dispositions. Compared with full-year 2013 average production of 84,527 boe per day, full-year 2014 production decreased 13 per cent due to significant property dispositions in late 2013 and dispositions in 2014, partly offset by production additions from the Cardium development program. Successful drilling at Lochend and Garrington in the Cardium formation and at Groundbirch in the Montney underscores the efficiency and strength of Pengrowth's conventional development program.
Capital expenditures
Fourth quarter capital expenditures were $258.8-million, with approximately 31 per cent invested at Lindbergh and 21 per cent invested on conventional operations. The remaining 48 per cent of fourth quarter capital expenditures were used for the acquisition of 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in northeastern British Columbia.
Full-year 2014 capital spending amounted to $904.0-million, of which approximately 49 per cent was invested at Lindbergh, 37 per cent invested on conventional operations and 14 per cent invested in the Bernadet land acquisition.
Lindbergh
Lindbergh, Pengrowth's 100-per-cent-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 bitumen production of 40,000 to 50,000 barrels per day, starting with the initial 12,500-barrel-per-day commercial phase coming on stream in 2015. Lindbergh's robust economics make it a strong, viable project even in the current low-commodity-price environment.
During the fourth quarter 2014, $80.4-million was invested at Lindbergh, bringing the full-year 2014 spending to $442.3-million. Construction and commissioning of the initial 12,500-barrel-per-day commercial phase of Lindbergh were completed on time with steaming operations commencing in December, 2014. Steam circulation on the 20-well pairs is following the same time line established for the pilot well pairs. Operations have commenced on all three well pads, and production is expected to build through 2015 as downhole pumps are installed. In addition to production from the pilot facility, production rates from the commercial project at well pad D03 reached approximately 1,800 bbl per day during the week of Feb. 21 through 25, 2015. The two additional well pads are continuing through initial phases of steam circulation.
The Lindbergh pilot delivered another strong year of results that demonstrated better than expected steam/oil and diluent-blending ratios and stronger-than-expected production performance. Operations at the pilot project continued to show strong results during the fourth quarter of 2014 with combined field production from the two well pairs averaging 1,689 bbl per day. The average instantaneous steam oil ratio for the fourth quarter of 2014 was 2.5. Since steaming commenced in February, 2012, cumulative production from the two well pairs exceeded 1.6 million barrels by Dec. 31, 2014, with a cumulative steam oil ratio of 2.1.
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 500 gross (250 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, providing low production decline rates and strong cash flow.
Development during the fourth quarter continued in the Greater Olds/Garrington area with an additional seven (3.2 net) wells drilled in the Cardium and an additional two (0.5 net) wells drilled in the Glauconite formation, all 100 per cent successful. Two of the new Cardium wells are on stream, and two others have been tested, with initial test data and early production results indicating performance that meets or exceeds type curve expectations. Pengrowth's fourth quarter 2014 development program also included three (0.8 net) wells in the Slave Point formation at Sawn Lake and one (1.0 net) injection well at Judy Creek, supporting incremental production and reserves in the miscible flood. Pengrowth also completed and tied in two Groundbirch Montney horizontal wells in the fourth quarter of 2014, completed with high-intensity multistage hydraulic fracturing technology. The initial production results from the two Groundbirch wells indicate performance that significantly exceeds Pengrowth's historical Groundbirch production results.
Pengrowth acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in northeastern British Columbia at the Nov. 5, 2014, Crown land sale. This acquisition extends Pengrowth's legacy position in the Bernadet area of four gross/net sections and is expected to provide significant scalable, low-risk development drilling inventory in addition to existing Montney inventory at Groundbirch. With the addition of the Bernadet lands, Pengrowth is now well positioned with a focused multiyear conventional drilling inventory of light oil and liquids-rich natural gas prospects that complement the company's thermal opportunities.
Operating expenses
Fourth quarter 2014 operating expenses were $94.5-million ($14.31 per boe) and represented a decrease of $7.9-million or 8 per cent compared with the third quarter 2014 operating expense of $102.4-million ($15.36 per boe). The improvement in expenses was primarily due to lower power and turnaround costs, combined with lower costs, resulting from the minor asset sales during the third quarter of 2014. On a per boe basis, fourth quarter operating expenses decreased $1.05 per boe as a result of the lower expenses, as mentioned herein.
Full-year 2014 operating expenses were $415.4-million ($15.53 per boe), compared with full-year 2013 expenses of $482.5-million ($15.64 per boe). Two thousand fourteen operating expenses decreased $67.1-million or 14 per cent due to the absence of operating expenses from properties divested throughout 2013 and 2014, as well as lower power costs, partly offset by increased turnaround costs in 2014. On a per boe basis, 2014 operating expenses decreased 11 cents per boe compared with 2013, driven by lower costs, offset by reduced production resulting from the 2013 and 2014 dispositions.
General and administrative expenses
Cash general and administrative expenses in the fourth quarter 2014 were $21.2-million ($3.21 per boe) compared with $20.6-million ($3.09 per boe) in the third quarter 2014. Fees associated with the reporting of the company's year-end reserves were the main reason for the increase in costs. On a per boe basis, cash G&A expenses increased 12 cents per boe compared with the third quarter due to the increase in costs as discussed herein.
Full-year 2014 cash G&A expenses of $84.3-million ($3.15 per boe) were $3.5-million lower compared with 2013 expenses of $87.8-million ($2.85 per boe) due to staffing decreases associated with the 2013 dispositions, as well as lower office rent. On a per boe basis, 2014 cash G&A expenses increased 30 cents per boe due to lower production volumes partly offset by lower expenses, as discussed herein.
Funds flow from operations
Fourth quarter 2014 funds flow from operations was $115.8-million (22 cents per share) compared with $129.0-million (24 cents per share) in the third quarter 2014. The 10-per-cent decrease in funds flow from operations compared with the third quarter 2014 was primarily due to the absence of volumes associated with minor property dispositions, temporary solution gas restrictions in the Swan Hills area and a decline in commodity prices. Offsetting the impact of lower commodity prices were realized commodity risk management gains and lower royalties and operating expenses.
Full-year 2014 funds flow from operations of $505.7-million (96 cents per share) decreased 10 per cent compared with 2013 funds flow of $560.9-million ($1.08 per share). The decrease in funds flow from operations was due to lower volumes resulting from the 2013 and 2014 property dispositions, which were mostly offset by an increase in natural gas prices and lower operating and interest expenses year over year.
Adjusted net income (loss)
Pengrowth recorded an adjusted net loss of $854.8-million ($1.61 per share) in the fourth quarter of 2014 and $879.0-million ($1.67 per share) for the full year, mainly due to a non-cash impairment charge of $994.6-million (approximately $858-million after tax). As a result of the significant downturn in the outlook for oil and natural gas prices, Pengrowth wrote down the book value of property, plant and equipment by $486.3-million, reduced the amount of recorded goodwill by $451.3-million, and wrote down $57.0-million of exploration and evaluation assets for the period ended Dec. 31, 2014. These non-cash charges did not affect the company's cash flows. Additional details regarding the impairment charges are available in management's discussion and analysis accompanying Pengrowth's year-end 2014 consolidated financial statements.
Summary of reserves results:
- Pengrowth replaced 399 per cent of 2014 total production, with 106.7
million boe of proved plus probable (2P) reserve additions in 2014, net of
dispositions.
- Total 2P reserves in 2014 increased 17 per cent to approximately 557.4 million boe
compared with 477.4 million boe at year-end 2013. Total proved reserves (1P) at
year-end 2014 increased 1 per cent to approximately 310.1 million boe from
307.0 million boe at year-end 2013.
- 2P reserve life index increased to 19.8 years at year-end 2014, a
14-per-cent increase from the year-end 2013 RLI of 17.4 years, due
primarily to increased 2P reserves at Lindbergh.
- Finding and development costs in 2014 were $22.33 per boe, including
changes in future development costs for 2P reserves. The 2014 F&D
costs, excluding changes to FDC, were $8.03 per boe for 2P reserves.
- Pengrowth's three-year weighted-average finding, development and
acquisition and F&D costs for 2P reserves were $20.09 per boe and
$20.22 per boe, respectively, including FDC ($8.42 per boe and $7.30 per
boe, respectively, excluding FDC).
Pengrowth's reserves and present values at year-end 2014 were based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd., effective Dec. 31, 2014, in its report dated Feb. 25, 2015, using GLJ's Jan. 1, 2015, price forecast and prepared in accordance with National Instrument 51-101 and the Canadian oil and gas evaluation handbook.
COMPANY INTEREST RESERVES SUMMARY
(as at Dec. 31, 2014)
Light and
medium Natural
crude Heavy gas Natural Total oil Per cent of
oil oil Bitumen liquids gas equivalent 2P oil
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (bcf) (Mboe) equivalent
Proved
producing 50,394 12,627 829 22,873 487.6 167,994 30%
Proved
developed
non-
producing 800 113 25,906 575 19.1 30,576 5%
Proved
undeveloped 13,137 5,484 77,113 832 89.5 111,480 20%
Total proved 64,331 18,224 103,848 24,279 596.2 310,051 56%
Total
probable 27,365 11,047 139,490 9,983 356.5 247,299 44%
Total proved
plus
probable 91,695 29,272 243,338 34,261 952.7 557,350 100%
Reserves reconciliation
Total 2P reserves increased 17 per cent in 2014 based on a total net reserves addition of 106.7 million boe, primarily due to drilling additions, positive technical revisions and acquisitions, partially offset by dispositions and reductions due to economic factors. The additional 2P reserves represented a replacement of 399 per cent of 2014 production. The most significant of these additions were reserves attributed to the Lindbergh thermal project, where 2P reserves increased by 101.4 million boe in 2014 over year-end 2013 numbers.
On a 1P basis, year-end 2014 reserves increased by 1 per cent compared with 2013. In total, 29.8 million boe of 1P reserves were added, including revisions and net of dispositions, replacing 111 per cent of 2014 production.
COMPANY INTEREST RESERVES RECONCILIATION 2014
Light and
medium Natural
crude Heavy gas Natural Total oil
oil oil Bitumen liquids gas equivalent
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (bcf) (Mboe)
Total proved
Dec. 31, 2013 73,293 19,312 81,727 25,342 644.1 307,016
Technical revisions 982 1,402 (1,103) 2,345 12.6 5,724
Economic factors (1,798) (473) -- (621) (21.3) (6,433)
Drilling 2,533 397 23,839 874 35.8 33,617
Improved recovery 35 -- -- 3 -- 43
Acquisitions 594 4 -- 108 1.0 865
Dispositions (3,559) (20) -- (75) (2.3) (4,030)
Production (7,748) (2,397) (615) (3,698) (73.8) (26,750)
Dec. 31, 2014 64,331 18,224 103,848 24,279 596.2 310,051
Total proved plus
probable
Dec. 31, 2013 103,473 30,195 142,565 35,091 996.4 477,385
Technical revisions (2,250) 932 (166) 1,626 6.3 1,199
Economic factors (1,243) (295) -- (543) (23.0) (5,908)
Drilling 3,741 927 101,554 1,809 54.0 117,029
Improved recovery -- -- -- 9 0.2 38
Acquisitions 907 4 -- 154 1.3 1,276
Dispositions (5,184) (95) -- (186) (8.7) (6,918)
Production (7,748) (2,397) (615) (3,698) (73.8) (26,750)
Dec. 31, 2014 91,696 29,272 243,338 34,262 952.7 557,350
SELECT PRICES FROM GLJ'S JAN. 1, 2015, FORECAST PRICES AND INFLATION RATES
WTI crude Edm light WCS crude Natural gas Inflation
oil crude oil oil at AECO rate
Year ($U.S./bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu) (%/year)
2014 (actual) $93.06 $94.77 $81.62 $4.52 --
2015 62.50 64.71 54.35 3.31 2.0
2016 75.00 80.00 67.20 3.77 2.0
2017 80.00 85.71 72.00 4.02 2.0
2018 85.00 91.43 76.80 4.27 2.0
2019 90.00 97.14 81.60 4.53 2.0
2020 95.00 102.86 86.40 4.78 2.0
2021 98.54 106.18 89.19 5.03 2.0
2022 100.51 108.31 90.98 5.28 2.0
2023 102.52 110.47 92.79 5.53 2.0
2024 104.57 112.67 94.65 5.71 2.0
Thereafter More than More than More than More than
2.0 %/yr 2.0 %/yr 2.0 %/yr 2.0 %/yr 2.0
BEFORE-INCOME-TAX NET PRESENT VALUE SUMMARY
(as at Dec. 31, 2014)
Per cent of
Discounted at 2P
($ millions, except Discounted
percentages) Undiscounted 5% 10% 15% 20% at 10%
Proved producing $3,456 $2,511 $1,965 $1,616 $1,376 37%
Proved developed non-
producing 839 700 598 520 458 11%
Proved undeveloped 3,283 1,636 875 488 276 17%
Total proved 7,578 4,846 3,438 2,624 2,109 65%
Total probable 7,238 3,442 1,820 1,031 607 35%
Total proved plus
probable 14,816 8,288 5,259 3,656 2,716 100%
Net asset value
The attached net asset value -- before income tax -- table provides a calculation of Pengrowth's estimated NAV based on the estimated future net revenues associated with Pengrowth's proved plus probable reserves.
NET ASSET VALUE -- BEFORE INCOME TAX
(as at Dec. 31, 2014)
($ millions, except percentages and
share numbers) Discounted at 5% Discounted at 10%
Value of total proved plus probable
reserves $8,288 $5,259
Undeveloped land 208 208
Long-term debt, including
convertible debentures and working
capital (1,809) (1,809)
Reclamation funds 60 60
Other assets/liabilities (asset
retirement obligations and commodity
contracts) 73 185
Net asset value 6,821 3,903
Shares outstanding (millions) 533 533
NAV per share ($ per share) 12.79 7.32
As of Dec. 31, 2014, Pengrowth's estimated NAV, discounted at 10 per cent, was $7.32 per share. The approximate 3-per-cent decrease from the year-end 2013 estimated NAV of $7.52 per share is primarily due to a lower reserve value resulting from lower commodity prices.
Finding, development and acquisition costs
During 2014, excluding information technology and office expenditures, Pengrowth spent $902.5-million on development and optimization activities, which added 32.9 million boe of 1P and 112.4 million boe of 2P reserves, including revisions, resulting in a 2P F&D cost of $22.33 per boe (including FDC). The largest 2P additions were at Lindbergh, where 2P reserves increased by 101.4 million boe due to further delineation drilling, submitting a regulatory application to expand the SAGD project and continued superior pilot performance. Included in this capital expenditure was $123.6-million spent to acquire 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in northeastern British Columbia, which have no reserves attributed to them at this time. Excluding the Bernadet land costs, the 2P F&D cost (including FDC) decreased by $1.10 per boe to $21.23 per boe.
Pengrowth's 2014 F&D and FD&A costs are summarized herein. 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 continuing development activity, inflationary changes in capital costs, and acquisition or disposition of assets. Pengrowth includes FD&A costs because it believes that acquisitions and dispositions can have a significant impact on its continuing reserve replacement costs.
F&D AND FD&A COSTS IN 2014
2012-2014
2014 2013 weighted average
Proved Proved Proved
plus plus plus
Proved probable Proved probable Proved probable
FD&A costs
excluding future
development cost
Exploration and
development
capital
expenditures -- $
millions $902.5 $902.5 $692.4 $692.4 $2,055.9 $2,055.9
Exploration and
development
reserve additions
including
revisions -- MMboe 32.9 112.4 83.4 65.3 137.3 281.5
Finding and
development cost --
$/boe 27.43 8.03 8.30 10.61 14.97 7.30
F&D recycle ratio,
$/$ 0.9 3.2 2.9 2.3 1.6 3.4
Net acquisition
(disposition)
capital -- $
millions (67.5) (67.5) (977.8) (977.8) 608.9 608.9
Net acquisition
(disposition)
reserve additions --
MMboe (3.1) (5.6) (45.6) (69.0) 30.2 34.8
Net acquisition
cost -- $/boe 21.77 12.05 21.43 14.17 20.16 17.50
Total capital
expenditures
including net
acquisitions
(dispositions) --
$ millions 835.0 835.0 (285.3) (285.3) 2,664.8 2,664.8
Reserve additions
including net
acquisitions
(dispositions) --
MMboe 29.8 106.7 37.8 (3.7) 167.5 316.3
Finding
development and
acquisition cost --
$/boe 28.02 7.82 (7.55) 76.66 15.91 8.42
FD&A costs
including future
development cost
Exploration and
development
capital
expenditures -- $
millions 902.5 902.5 692.4 692.4 2,055.9 2,055.9
Exploration and
development
change in FDC -- $
millions (51.7) 1,607.2 1,031.7 741.2 1,084.6 3,636.4
Exploration and
development
capital including
change in FDC -- $
millions 850.8 2,509.7 1,724.1 1,433.6 3,140.5 5,692.3
Exploration and
development
reserve additions
including
revisions -- MMboe 32.9 112.4 83.4 65.3 137.3 281.5
Finding and
development cost --
$/boe 25.86 22.33 20.67 21.96 22.87 20.22
F&D recycle ratio,
$/$ 1.0 1.1 1.2 1.1 1.1 1.2
Net acquisition
(disposition)
capital -- $
millions (67.5) (67.5) (977.8) (977.8) 608.9 608.9
Net acquisition
(disposition) FDC --
$ millions (5.3) (32.2) (224.7) (381.2) (0.2) 53.8
Net acquisition
(disposition)
capital including
change in FDC -- $
millions (72.8) (99.7) (1,202.5) (1,359.0) 608.7 662.7
Net acquisition
(disposition)
reserve additions --
MMboe (3.1) (5.6) (45.6) (69.0) 30.2 34.8
Net acquisition
cost -- $/boe 23.48 17.80 26.36 19.70 20.16 19.04
Total capital
expenditures
including net
acquisitions
(disposition) -- $
millions 835.0 835.0 (285.3) (285.3) 2,664.8 2,664.8
Total change in
FDC -- $ millions (57.0) 1,575.0 807.0 360.0 1,084.4 3,690.2
Total capital
including change
in FDC -- $
millions 778.0 2,410.0 521.7 74.6 3,749.2 6,355.0
Reserve additions
including net
acquisitions
(disposition) --
MMboe 29.8 106.7 37.8 (3.7) 167.5 316.3
Finding
development and
acquisition cost
including FDC --
$/boe 26.11 22.57 13.80 (20.05) 22.38 20.09
2012-2014
2014 2013 weighted average
Operating netback
($/boe) $25.64 $24.35 $24.50
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
(as at Dec. 31, 2014)
Operating Development
($ millions) Revenue Royalties costs costs
Proved producing $10,159 $1,665 $4,576 $157
Proved developed non-
producing 1,897 312 614 121
Proved undeveloped 9,468 2,089 2,382 1,667
Total proved 21,524 4,066 7,572 1,944
Total probable 20,026 4,320 5,364 3,013
Total proved plus
probable 41,550 8,386 12,937 4,957
Revenue Revenue
Abandonment before Income after
($ millions) costs income tax tax income tax
Proved producing $305 $3,456 -- $3,456
Proved developed non-
producing 10 839 $5 834
Proved undeveloped 47 3,283 915 2,368
Total proved 363 7,578 920 6,658
Total probable 92 7,238 1,942 5,296
Total proved plus
probable 455 14,816 2,862 11,954
Reserve life index
Pengrowth's 2014 proved RLI decreased marginally to 11.7 years from 11.8 years in 2013. The RLI for proved plus probable reserves increased to 19.8 years at year-end 2014, a 14-per-cent increase from year-end 2013 RLI of 17.4 years.
HISTORICAL RESERVE LIFE INDEX
Reserve line index (years) 2014 2013 2012 2011 2010
Proved producing 7.2 7.4 7.6 7.6 7.2
Total proved 11.7 11.8 9.2 9.0 8.2
Total proved plus probable 19.8 17.4 14.7 12.0 11.1
RLI refers to the number of years determined by dividing 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 relevant year's GLJ report.
Reserves and contingent resources classification
The attached summary of reserves and contingent resources table summarizes GLJ's estimates of reserves and contingent resources, as of year-end 2014, for the Lindbergh thermal property and Groundbirch natural gas property.
SUMMARY OF RESERVES AND CONTINGENT RESOURCES
Reserves Contingent resources
Proved +
Proved + probable + Low Best High
Field Proved probable possible estimate estimate estimate
Lindbergh
(MMbbl) 103.8 243.3 316.6 50.6 100.6 149.0
Groundbirch
(bcf) 85.2 228.2 279.6 474.5 634.4 990.9
The reserves attributed to Lindbergh increased in 2014 due to continuing reservoir delineation and the submission of the regulatory application for expansion of development of the commercial SAGD project. Contingent resources decreased as a result of significant volumes being reclassified 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, firm development plans beyond the initial expansion phase, high-quality project design, and cost estimates and commitment by Pengrowth for future development.
Contingent resources at Groundbirch in 2014 increased primarily due to production performance from the additional drilling that was carried out in 2014, coupled with offsetting development activity in the play. The Groundbirch tight gas resource is in early-stage evaluation, delineation and development. Additional drilling, completion and testing data are required for planning and design purposes. 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.
Reserves and contingent resources included herein are stated on a company interest basis unless noted otherwise. All reserves information has been prepared in accordance with NI 51-101 (standards of disclosure for oil and gas activities) and Canadian oil and gas evaluation handbook. In addition to the information disclosed in this news release, more detailed information is included in Pengrowth's annual information form dated Feb. 26, 2015, which is available on SEDAR and on EDGAR.
Financial flexibility
Pengrowth remains committed to ensuring its financial health and flexibility during these volatile times. On Jan. 21, 2015, the company announced several measures intended to safeguard its financial health and sustainability in 2015. These measures included a significantly reduced capital program for 2015, the deferral of the second commercial phase of Lindbergh, a continued focus on hedging and a revised dividend payout rate.
To mitigate commodity price risk and provide a measure of stability and predictability to cash flows, Pengrowth continues its active hedging strategy. At Feb. 26, 2015, Pengrowth has approximately 26,000 bbl per day of 2015 crude oil production (75 per cent of 2015 estimated oil production) hedged at $93.96 per bbl and approximately 21,000 bbl per day of 2016 crude oil production (61 per cent of 2015 estimated oil production) hedged at $89.79 per bbl.
For natural gas, Pengrowth has approximately 102 million cubic feet per day of 2015 natural gas production (54 per cent of 2015 estimated gas production) hedged at $3.73 per thousand cubic feet and approximately 81 million cubic feet per day of 2016 natural gas production (43 per cent of estimated 2015 gas production) hedged at $3.46 per thousand cubic feet. Pengrowth has also entered into significant natural gas hedges for 2017 and 2018 at prices in excess of AECO $3.50 per thousand cubic feet.
Details of Pengrowth's commodity risk management contracts in place as at Feb. 26, 2015, are summarized in the attached summary of commodity risk management contracts table.
SUMMARY OF COMMODITY RISK MANAGEMENT CONTRACTS
Average price
Volume ($Cdn)
Crude oil (bbl per day)
2015 26,000 $93.96
2016 20,852 $89.79
Natural gas (Mcf per day)
2015 101.8 $3.73
2016 80.5 $3.46
2017 47.9 $3.72
2018 54.5 $3.64
Following the repayment of approximately $100-million of convertible debentures that came due on Dec. 31, 2014, Pengrowth's senior unsecured debt totalled approximately $1.72-billion. This included $191-million drawn on its $1-billion credit facility. The senior unsecured revolving credit facility has a maturity date of July 26, 2017. In addition to balancing cash inflows and outflows in 2015, Pengrowth is targeting further reductions to total debt. Pengrowth remains fully compliant with the various financial covenants that it is subject to under its long-term debt and bank facilities and does not anticipate breaching any of its financial covenants.
Forecast guidance summary
for 2015
Pengrowth's board of directors approved a $200-million capital budget for 2015, representing a decrease of 78 per cent from its 2014 actual capital expenditures of $904.0-million. The reduced capital budget will focus on optimization and enhancement activities, targeting continuing production, and does not contemplate an active drilling program. Pengrowth's 2015 capital program has been designed with an emphasis on preserving its financial health and sustainability in a low-commodity-price environment while paying shareholders a monthly dividend of two cents per share.
Previous capital spending at Lindbergh has established a low-decline production base going forward that Pengrowth expects to maintain with a lower level of capital investment through 2016, which serves to preserve the financial flexibility to take advantage of the significant growth opportunities that the company has at Lindbergh, in the Montney and in the Cardium, when commodity prices improve.
Pengrowth is maintaining spending on its asset integrity and maintenance programs to mitigate risk to its employees and the environment.
Pengrowth's 2015 capital budget was based on the assumption of a WTI crude oil price of $50 (U.S.) per bbl, an AECO natural gas price of $2.75 (Canadian) per thousand cubic feet and an 85-U.S.-cent-per-$1-(Canadian) exchange rate.
The 2015 capital budget and revised dividend rate reflect a balance whereby capital expenditures and dividends are expected to be less than internally generated funds flow from operations, with any and all excess funds flow being directed toward reducing debt. There will be a strong emphasis in 2015 on reducing Pengrowth's indebtedness.
A summary of Pengrowth's 2015 operating and financial guidance is provided in the attached operating and financial guidance for 2015 table.
OPERATING AND FINANCIAL GUIDANCE FOR 2015
Average daily production volume (boe per day) 73,000 to 75,000
Total capital expenditures ($ millions) $190 to $210
Royalties (% of sales) 12 to 15
Net operating costs ($ per boe) 15.50 to 16.50
Cash G&A expense ($ per boe) 3.20 to 3.30
Outlook
Pengrowth's management team and its board of directors have moved quickly and decisively to take steps to ensure that the financial health and sustainability of the company remains intact. These steps include substantially decreasing capital expenditures, deferring Lindbergh phase 2 spending, reducing the dividend by 50 per cent and significantly enhancing the company's focus on all aspects of capital, operating, and general and administrative cost structures. Delivering on these measures will help ensure that Pengrowth emerges as a stronger company when commodity prices strengthen.
Pengrowth's audited consolidated financial statements for the three and 12 months ended Dec. 31, 2014, and related management's discussion and analysis, as well as Pengrowth's annual information form dated Feb. 26, 2015, can be viewed on Pengrowth's website. They will also be available on SEDAR and on EDGAR.
Conference call
Pengrowth will host a conference call for investors at 6:30 a.m. Mountain Time on Feb. 27, 2015. To participate, callers may dial in by telephone or participate on-line in listen-only mode by audio webcast. To ensure timely participation in the teleconference, callers are encouraged to dial in 10 minutes prior to commencement of the call to register.
Dial-in numbers:
Toll-free: 800-355-4959
Toronto local: 416-340-2216
We seek Safe Harbor.
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