CALGARY, ALBERTA--(Marketwired - March 12, 2014) -
NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES
Birchcliff Energy Ltd. ("Birchcliff") (TSX:BIR) is pleased to provide estimates of its 2014 first quarter production and funds flow, provide an operational update and announce its 2013 audited financial statements. The audited financial statements are consistent with the unaudited financial results announced in the press release issued by Birchcliff on February 12, 2014. The full text of the 2013 audited financial statements and the related Management's Discussion and Analysis is available on Birchcliff's website at www.birchcliffenergy.com and will be available on SEDAR at www.sedar.com.
Certain information contained in this press release is repeated from Birchcliff's February 12, 2014 press release, including the 2013 financial and operational results and highlights from the 2013 independent Reserves Evaluation and the 2013 independent Montney/Doig Natural Gas Resource Assessment.
Jeff Tonken, President and CEO of Birchcliff said, "As a result of significant natural gas production growth and the cost efficiency of our natural gas plant in the Pouce Coupe South area (the "PCS Gas Plant"), coupled with strong natural gas prices, Birchcliff is now capable of funding the substantial majority of its $347.1 million 2014 capital expenditure program out of internally generated funds flow."
PRESS RELEASE HIGHLIGHTS
2014 First Quarter Estimates and Outlook
- Record first quarter average production forecast to be approximately 31,800 boe per day, consisting of 83.6% natural gas and 16.4% crude oil and natural gas liquids.
- Record first quarter funds flow forecast to be approximately $83 million ($0.58 per common share), assuming a realized natural gas price at the wellhead of $6.12 per Mcf (based on an expected average AECO daily spot price of $5.40 per GJ) and a realized crude oil price at the wellhead of $89.11 per bbl for the first quarter. This forecast represents a 66% increase from funds flow of $50.1 million in the fourth quarter of 2013 and a 110% increase from $39.4 million in the first quarter of 2013.
- Exit production for 2014 is expected to be between 37,500 and 39,500 boe per day, with plans to drill 40 (39.5 net) wells in 2014.
- A substantial majority of the $347.1 million 2014 capital expenditure program expected to be funded out of internally generated funds flow.
- Birchcliff's natural gas production is unhedged for the winter months of 2014.
- Natural gas hedging program in place for 2014 summer months (April - October), with Birchcliff contracting forward physical sales of 75,000 GJ's per day for approximately $4.35 per Mcf, representing 41% of its estimated gas volumes for that period.
- Phase IV expansion planned for the fall of 2014 will bring processing capacity of our PCS Gas Plant from current licensed capacity of 150 MMcf per day to 180 MMcf per day for a modest capital investment of approximately $11.6 million.
- Strategic acquisition on January 15, 2014, purchasing a partner's 30% working interest in land and production on the Montney/Doig Natural Gas Resource Play, giving Birchcliff a 100% working interest in 38 sections of land. Approximately 9.6 MMcfe (1,600 boe per day) of production was acquired, the majority of which goes to Birchcliff's PCS Gas Plant.
2014 Operational Update
- Drilling results to date of 11 (11.0 net) wells, consisting of 7 (7.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and 4 (4.0 net) Charlie Lake horizontal light oil wells in the Worsley area.
- Birchcliff currently has four drilling rigs at work. Two rigs are active in the Pouce Coupe area, drilling Montney/Doig horizontal natural gas wells on multi-well pads, which will allow these rigs to drill continuously through break-up. One rig is active in the Worsley area, drilling Charlie Lake horizontal oil wells and one rig is in the Progress area drilling a Doig oil well.
2013 Financial and Operational Results
- 2013 average production of 25,829 boe per day, a 13.3% increase over 2012 average production of 22,802 boe per day.
- Record funds flow of $174.4 million or $1.22 per basic share, a 45.0% increase from 2012.
- Net income of $65.4 million, a 396% increase from $13.2 million in 2012. Net income in 2013, excluding the impact of the sale of assets, was $40.1 million.
- Long-term bank debt of $394 million against available lines of credit of approximately $600 million. Total year-end debt, including working capital deficiency of $60 million, was $454 million.
- Operating costs of $5.68 per boe, down 6.3% from $6.06 per boe in 2012.
- General and administrative costs of $2.19 per boe, down 20.4% from $2.75 per boe in 2012.
- Top tier operating performance at the PCS Gas Plant. With the AECO natural gas price averaging $3.17 per Mcf during 2013 Birchcliff realized $3.77 per Mcfe, resulting in an operating netback of $2.99 per Mcfe for natural gas processed at the PCS Gas Plant.
- Capital expenditures in 2013 was $270.1 million, $215.8 million net of dispositions.
- Drilled a total of 43 (41.67 net) wells in 2013, consisting of:
- 26 (26.0 net) wells on our Montney/Doig Natural Gas Resource Play, including 25 (25.0 net) horizontal natural gas wells and 1 (1.0 net) vertical exploration well;
- 13 (13.0 net) wells on our Worsley Charlie Lake Light Oil Resource Play, all of which were horizontal wells; and
- 4 (2.67 net) wells on our Halfway Light Oil Play, all of which were horizontal wells.
- Undeveloped land base of 576,893 (544,917 net) acres at December 31, 2013, up from 544,129 (506,024 net) acres at December 31, 2012, with a 94% average working interest.
- Added 90,645.3 (90,325.3 net) acres or 141.3 (141.1 net) sections of undeveloped land in 2013, substantially all at 100% working interest, and all within Birchcliff's core area of the Peace River Arch of Alberta.
2013 Fourth Quarter Financial and Operational Results
- Fourth quarter production averaged 28,391 boe per day, a 15.1% increase over production of 24,662 boe per day in the third quarter of 2013 and a 6.5% increase from 26,655 boe per day in the fourth quarter of 2012.
- Record quarterly funds flow of $50.1 million, a 16.3% increase from the third quarter of 2013 and a 25.6% increase from the fourth quarter of 2012.
- Net income of $37.1 million in the fourth quarter of 2013, a 265% increase from the third quarter of 2013 and a 488% increase from the fourth quarter of 2012. Excluding the impact of the sale of assets in the fourth quarter, Birchcliff had net income of $11.8 million in the fourth quarter of 2013.
- Operating costs of $5.44 per boe, down 3.9% from $5.66 per boe in the third quarter of 2013 and down 7.5% from $5.88 per boe in the fourth quarter of 2012.
- $54.7 million strategic disposition, net of adjustments, of predominately non-operated, low working interest, non-core assets in the Progress area of Alberta.
- Capital expenditures in the fourth quarter of $73.0 million, $18.2 million net of dispositions.
- Drilled 12 (11.5 net) wells in the fourth quarter of 2013, comprising of 7 (7.0 net) Montney/Doig horizontal natural gas wells, 4 (4.0 net) Charlie Lake horizontal oil wells and 1 (0.5 net) Halfway horizontal oil well, all of which were successful.
2013 Independent Reserves Evaluation
- Proved plus probable reserves of 370.1 MMboe, a 16.5% increase from December 31, 2012. Added 6.9 boe of proved plus probable reserves for each boe that was produced and sold in 2013.
- Proved reserves of 220.0 MMboe, an 18.3% increase from December 31, 2012.
- Proved developed producing reserves of 62.0 MMboe, a 13.6% increase. This is a net increase of 7.4 MMboe from 54.6 MMboe at December 31, 2012.
- After taking into account 2013 production of 9.4 MMboe and 2013 dispositions of 1.1 MMboe, Birchcliff added 17.9 MMboe of proved developed producing reserves, which is 32.9% of Birchcliff's proved developed producing reserves at December 31, 2012.
- Increased potential net future Montney/Doig horizontal natural gas well drilling locations to 2,254 at December 31, 2013, up from 1,929 at December 31, 2012, as a result of land acquisitions and drilling.
2013 Finding and Development Costs and Recycle Ratios
- Finding, development and acquisition ("FD&A") costs on a proved plus probable basis of $3.46 per boe, excluding future development capital and $8.60 per boe, including future development capital.
- Operating netback recycle ratio of 6.5 and funds flow netback recycle ratio of 5.3, in each case excluding future development costs, based on finding, development and acquisition costs and proved plus probable reserves.
2013 Independent Montney/Doig Natural Gas Resource Assessment
- Assessment of Birchcliff's land that have potential for the Montney/Doig Natural Gas Resource Play. On a best estimate basis, reflecting Birchcliff's working interest:
- Total petroleum initially-in-place of 52.0 Tcfe, a 31% increase from December 31, 2012;
- Prospective resources of 15.8 Tcfe, a 22% increase from December 31, 2012; and
- Contingent resources of 6.5 Tcfe, a 35% increase from December 31, 2012.
2013 FINANCIAL AND OPERATIONAL HIGHLIGHTS
| Three months ended December 31, |
Twelve months ended December 31, |
||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||
| OPERATING | |||||||||
| Average daily production | |||||||||
| Light oil - (barrels) | 4,227 | 3,986 | 4,030 | 4,270 | |||||
| Natural gas - (thousands of cubic feet) | 138,132 | 131,120 | 125,712 | 106,868 | |||||
| NGLs - (barrels) | 1,142 | 816 | 847 | 721 | |||||
| Total - barrels of oil equivalent (6:1) | 28,391 | 26,655 | 25,829 | 22,802 | |||||
| Average sales price ($ CDN) | |||||||||
| Light oil - (per barrel) | 81.52 | 83.38 | 89.89 | 84.45 | |||||
| Natural gas - (per thousand cubic feet) | 3.81 | 3.43 | 3.41 | 2.63 | |||||
| NGLs - (per barrel) | 85.45 | 80.44 | 88.45 | 83.78 | |||||
| Total - barrels of oil equivalent(6:1) | 34.10 | 31.78 | 33.52 | 30.80 | |||||
| NETBACK AND COST ($ per barrel of oil equivalent at 6:1) | |||||||||
| Petroleum and natural gas revenue | 34.11 | 31.81 | 33.59 | 30.82 | |||||
| Royalty expense | (2.68 | ) | (2.52 | ) | (2.92 | ) | (2.90 | ) | |
| Operating expense | (5.44 | ) | (5.88 | ) | (5.68 | ) | (6.06 | ) | |
| Transportation and marketing expense | (2.52 | ) | (2.09 | ) | (2.46 | ) | (2.28 | ) | |
| Netback | 23.47 | 21.32 | 22.53 | 19.58 | |||||
| General & administrative expense, net | (2.54 | ) | (2.66 | ) | (2.19 | ) | (2.75 | ) | |
| Interest expense | (1.77 | ) | (2.41 | ) | (2.28 | ) | (2.42 | ) | |
| Other income | - | - | 0.44 | - | |||||
| Funds flow netback | 19.16 | 16.25 | 18.50 | 14.41 | |||||
| Stock-based compensation expense, net | (0.37 | ) | (0.41 | ) | (0.43 | ) | (0.60 | ) | |
| Depletion and depreciation expense | (11.70 | ) | (11.75 | ) | (11.54 | ) | (11.48 | ) | |
| Accretion expense | (0.24 | ) | (0.18 | ) | (0.23 | ) | (0.21 | ) | |
| Amortization of deferred financing fees | (0.10 | ) | (0.08 | ) | (0.09 | ) | (0.09 | ) | |
| Gain on sale of assets | 12.93 | - | 3.58 | 0.46 | |||||
| Unrealized loss on financial instruments | (0.15 | ) | - | (0.04 | ) | - | |||
| Dividends on Series C Preferred Shares | (0.33 | ) | - | (0.20 | ) | - | |||
| Income tax expense | (5.01 | ) | (1.26 | ) | (2.61 | ) | (0.91 | ) | |
| Net income | 14.19 | 2.57 | 6.94 | 1.58 | |||||
| Dividends on Series A Preferred Shares | (0.38 | ) | (0.41 | ) | (0.43 | ) | (0.19 | ) | |
| Net income to common shareholders | 13.81 | 2.16 | 6.51 | 1.39 | |||||
| FINANCIAL | |||||||||
| Petroleum and natural gas revenue ($000's) | 89,092 | 78,001 | 316,637 | 257,206 | |||||
| Funds flow from operations ($000's)(1) | 50,060 | 39,848 | 174,361 | 120,259 | |||||
| Per common share - basic ($)(1) | 0.35 | 0.28 | 1.22 | 0.88 | |||||
| Per common share - diluted ($)(1) | 0.34 | 0.28 | 1.20 | 0.86 | |||||
| Net income ($000's) | 37,062 | 6,305 | 65,417 | 13,196 | |||||
| Net income to common shareholders ($000's)(2) | 36,062 | 5,305 | 61,417 | 11,617 | |||||
| Per common share - basic ($)(2) | 0.25 | 0.04 | 0.43 | 0.08 | |||||
| Per common share - diluted ($)(2) | 0.25 | 0.04 | 0.42 | 0.08 | |||||
| Common shares outstanding | |||||||||
| End of period - basic | 143,676,661 | 141,596,279 | 143,676,661 | 141,596,279 | |||||
| End of period - diluted | 163,547,913 | 162,997,383 | 163,547,913 | 162,997,383 | |||||
| Weighted average common shares for period - basic | 143,062,664 | 141,585,180 | 142,421,939 | 137,083,519 | |||||
| Weighted average common shares for period - diluted | 145,319,288 | 144,238,774 | 145,006,118 | 139,904,484 | |||||
| Dividends on Series A Preferred Shares ($000's) | 1,000 | 1,000 | 4,000 | 1,579 | |||||
| Dividends on Series C Preferred Shares ($000's) | 875 | - | 1,913 | - | |||||
| Capital expenditures, net ($000's) | 18,188 | 32,137 | 215,770 | 298,903 | |||||
| Long-term bank debt ($000's) | 393,967 | 432,563 | 393,967 | 432,563 | |||||
| Working capital deficit ($000's)(3) | 60,071 | 29,567 | 60,071 | 29,567 | |||||
| Total debt ($000's) | 454,038 | 462,130 | 454,038 | 462,130 | |||||
| (1) | Funds flow from operations and per common share amounts are non-GAAP measures that represent cash flow from operating activities as per the Statements of Cash Flows before the effects of changes in non-cash working capital and decommissioning expenditures. Per common share amounts are calculated by dividing funds flow from operations by the weighted average number of basic or diluted common shares outstanding for the period. |
| (2) | Net income to common shareholders is calculated using net income as determined in accordance with GAAP, adjusted for dividends paid on Series A Preferred Shares. Per common share amounts are calculated by dividing net income to common shareholders by the weighted average number of basic or diluted common shares outstanding for the period. |
| (3) | Excludes the fair value of financial instruments and related deferred premium. |
2014 OUTLOOK
Birchcliff's 2014 capital budget is $347.1 million (including $56.0 million for a strategic acquisition in January 2014).
As a result of significant natural gas production growth and the cost efficiency of our PCS Gas Plant, coupled with strong natural gas prices, Birchcliff is now capable of funding a substantial majority of its 2014 capital expenditure program out of internally generated cash flow. This will result in Birchcliff significantly improving its balance sheet while at the same time continuing to post significant production and reserves growth.
We expect production in the first quarter of 2014 to be approximately 31,800 boe per day and forecast record first quarter funds flow to be approximately $83 million ($0.58 per common share), assuming a realized natural gas price at the wellhead of $6.12 per Mcf (based on an expected average AECO daily spot price of $5.40 per GJ) and a realized crude oil price at the wellhead of $89.11 per bbl for the first quarter. This forecast represents a 66% increase from funds flow of $50.1 million in the fourth quarter of 2013 and a 110% increase from $39.4 million in the first quarter of 2013.
We expect exit production in 2014 to be between 37,500 and 39,500 boe per day. Planned drilling activities in 2014 include 40 (39.5 net) wells.
Birchcliff's natural gas production during the winter of 2014 is unhedged and as a result we are receiving the full benefit of the high natural gas prices.
Birchcliff has contracted forward physical sales of 75,000 GJ per day for approximately $4.35 per Mcf, representing 41% of our estimated natural gas volumes during the summer months, April 1 to October 31, 2014. We have no current intention of contracting forward physical sales of natural gas for the winter months of 2015, however in late 2014 we will consider hedging natural gas for the 2015 summer months.
Our PCS Gas Plant is currently licensed to process up to 150 MMcf per day of natural gas. The Phase IV expansion planned for the fall of 2014 will bring processing capacity to 180 MMcf per day by adding additional compression and sales pipeline capacity for a modest capital investment of approximately $11.6 million.
We remain focused on our strategy - growth by the drill bit, in our core area of the Peace River Arch of Alberta. We continue to use the same services, in the same area, directed by the same experienced Birchcliff personnel, which provides consistency, repeatability and reliability in our operations.
Our record production, low cost structure, together with high natural gas prices have given us tremendous momentum for strong financial results and production growth in 2014.
2014 OPERATIONAL UPDATE
Year to date drilling results include the drilling of 11 (11.0 net) wells, consisting of 7 (7.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and 4 (4.0 net) Charlie Lake horizontal light oil wells in the Worsley area.
Birchcliff currently has four drilling rigs at work. Two rigs are active in the Pouce Coupe area, drilling Montney/Doig horizontal natural gas wells on multi-well pads, which will allow these rigs to drill continuously through break-up. One rig is active in the Worsley area, drilling Charlie Lake horizontal oil wells and one rig is in the Progress area drilling a Doig oil well.
2013 FINANCIAL AND OPERATIONAL RESULTS
2013 Production
Production in 2013 averaged 25,829 boe per day, which is a 13.3% increase over 2012 average production of 22,802 boe per day. Production per common share increased 9.0% from 2012. This increase was achieved through the success of Birchcliff's capital drilling program and increased incremental production from new horizontal natural gas wells on the Montney/Doig Natural Gas Resource Play that are processed through Birchcliff's PCS Gas Plant.
Production consisted of approximately 81% natural gas and 19% crude oil and natural gas liquids in 2013. Approximately 73% of Birchcliff's natural gas production and 61% of corporate production was processed at the PCS Gas Plant during 2013.
2013 Funds Flow and Earnings
2013 funds flow was approximately $174.4 million or $1.22 per common share, a 45.0% increase from 2012. This increase was a result of increased natural gas production, the 32.6% increase in the average AECO natural gas spot price from $2.39 per Mcf in 2012 to $3.17 per Mcf in 2013 and lower operating costs on a per unit basis.
Birchcliff recorded net income available to common shareholders of $61.4 million or $0.43 per common share in 2013 as compared to $11.6 million or $0.08 per common share in 2012. This was a 429% increase in net income from 2012. Net income available to common shareholders in 2013 was $36.1 million.
2013 Debt and Capitalization
At December 31, 2013, Birchcliff's long-term bank debt was $394 million from available credit facilities of approximately $600 million. Total debt, including the working capital deficit of $60 million, was $454 million, as compared to $462 million at December 31, 2012.
Birchcliff expects that as a result of significant reserve additions in 2013, its bank credit facilities will be increased during its normal credit review in May 2014.
At December 31, 2013, Birchcliff had 143,676,661 basic common shares outstanding.
2013 Operating and G&A Costs
Operating costs in 2013 were $5.68 per boe, down 6.3% from $6.06 per boe in 2012. This reduction of operating costs on a per boe basis was largely due to the cost benefits achieved from processing increased volumes of natural gas through the PCS Gas Plant and implementation of various optimization initiatives.
General and administrative expenses of $2.19 per boe were down 20.4% from $2.75 per boe in 2012 and the Corporation expects this trend to continue as Birchcliff increases production without having to add significant additional resources.
2013 Capital Expenditure
During the year ended December 31, 2013, Birchcliff had capital expenditures of $270.1 million, $215.8 million net of dispositions. Capital expenditures in 2013 were $23.5 million above Birchcliff's budgeted capital program of $246.6 million, with the expanded portion of the budget primarily directed toward strategic land sale purchases in the fourth quarter and the drilling of 3 (3.0 net) additional Montney/Doig natural gas wells in late 2013, which kept our drilling rigs working until year end. These additional wells were brought on production early in the first quarter of 2014.
2013 PCS Gas Plant Netbacks
Processing increased volumes of natural gas at the PCS Gas Plant has materially improved Birchcliff's funds flow and net earnings. In 2013, net operating costs for natural gas processed at the PCS Gas Plant was $0.37 per Mcfe ($2.24 per boe) and the estimated operating netback was $2.99 per Mcfe ($17.92 per boe). The following table details Birchcliff's annual net production and operating netback for wells producing to the PCS Gas Plant, on a production month basis.
| Production Processed through the PCS Gas Plant | Twelve months ended | Twelve months ended | |||||||
| December 31, 2013(1) | December 31, 2012 | ||||||||
| Average daily production, net to Birchcliff: | |||||||||
| Natural gas (Mcf) | 91,666 | 59,327 | |||||||
| Oil & NGLs (bbls) | 527 | 204 | |||||||
| Total boe (6:1) | 15,805 | 10,092 | |||||||
| Percentage of corporate natural gas production | 73 | % | 56 | % | |||||
| Percentage of corporate production | 61 | % | 44 | % | |||||
| Netback and cost: | $/Mcfe | $/boe | $/Mcfe | $/boe | |||||
| Petroleum and natural gas revenue(2) | 3.77 | 22.64 | 2.91 | 17.44 | |||||
| Royalty expense | (0.16 | ) | (0.93 | ) | (0.11 | ) | (0.67 | ) | |
| Operating expense, net of recoveries | (0.37 | ) | (2.24 | ) | (0.35 | ) | (2.08 | ) | |
| Transportation and marketing expense | (0.25 | ) | (1.55 | ) | (0.23 | ) | (1.37 | ) | |
| Estimated operating netback | 2.99 | 17.92 | 2.22 | 13.32 | |||||
| Operating margin(3) | 79 | % | 79 | % | 76 | % | 76 | % | |
| (1) | The PCS Gas Plant processed an average of 109 MMcf per day of gross raw gas at the inlet in 2013, against a licensed inlet capacity of 150 MMcf per day at December 31, 2013. |
| (2) | AECO natural gas price averaged $3.17 per Mcf and $2.39 per Mcf during 2013 and 2012, respectively. |
| (3) | Operating margin at the PCS Gas Plant is determined by dividing the estimated operating netback by petroleum and natural gas revenue in the period. |
As illustrated in the table below, after Birchcliff began processing natural gas at the PCS Gas Plant in early 2010, total corporate operating costs on a per boe basis have trended downward as an increasing percentage of corporate natural gas sales volumes have been processed at the PCS Gas Plant.
To view the table, Corporate Operating Costs per Boe vs. % of Total Natural Gas Sales Volumes Processed at the PCS Gas Plant, please visit the following link: http://media3.marketwire.com/docs/932816-birF1.pdf.
2013 Drilling Program
Birchcliff's 2013 drilling program was focused on our two proven resource plays, the Montney/Doig Natural Gas Resource Play and the Worsley Charlie Lake Light Oil Resource Play. Birchcliff actively employs the evolving technology utilized by leaders in the industry regarding horizontal well drilling and the related multi-stage fracture stimulation technology.
During 2013, Birchcliff drilled 43 (41.67 net) wells, consisting of 26 (26.0 net) natural gas wells and 17 (15.67 net) oil wells. The natural gas wells included 25 (25.0 net) Montney/Doig horizontal wells and 1 (1.0 net) Montney/Doig vertical exploration well. The oil wells included 13 (13.0 net) Worsley Charlie Lake horizontal light oil wells and 4 (2.67 net) Halfway horizontal light oil wells. All horizontal wells drilled in 2013 utilized the latest advancements in multi-stage fracture stimulation technology.
2013 Land
Birchcliff's undeveloped land base at December 31, 2013 was 576,893 (544,917 net) acres, up from 544,129 (506,024 net) acres at December 31, 2012, with a 94% average working interest.
During 2013, Birchcliff added 90,645.3 (90,325.3 net) acres, or 141.6 (141.1 net) sections of undeveloped land, substantially all at 100% working interest, and all in Birchcliff's core area of the Peace River Arch of Alberta. The undeveloped land acquired during 2013 includes 12.5 (12.5 net) sections right in the middle of our Pouce Coupe development area, as well as 33 (33.0 net) sections in the Elmworth/Sinclair area where Birchcliff is planning further drilling to delineate the Montney/Doig Natural Gas Resource Play.
Birchcliff's land base primarily consists of large contiguous blocks of high working interest acreage located near facilities owned and/or operated by Birchcliff or near third party infrastructure. Substantially all of the new land has been purchased without partners at 100% working interest.
Birchcliff continued to strategically add lands on resource plays during 2013. The following table summarizes Birchcliff's land holdings on resource plays at December 31, 2013.
| Resource Play Land Holdings | December 31, 2013 | ||
| Working Interest |
Gross (acres) |
Net (acres) |
|
| Middle/Lower Montney Play | 93.3% | 209,920 | 195,821 |
| Basal Doig/Upper Montney Play | 92.4% | 196,640 | 181,715 |
| Worsley Charlie Lake Light Oil Play | 98.7% | 125,280 | 123,610 |
| Duvernay Play | 99.8% | 168,320 | 167,936 |
| Nordegg Play | 85.8% | 432,960 | 371,571 |
| Banff/Exshaw Play | 99.3% | 447,360 | 443,669 |
2013 FOURTH QUARTER RESULTS
Fourth quarter production averaged 28,391 boe per day, which is a 15.1% increase over production of 24,662 boe per day in the third quarter of 2013 and a 6.5% increase from 26,655 boe per day in the fourth quarter of 2012.
Funds flow was $50.1 million, which is a 16.3% increase from $43.1 million in the third quarter of 2013 and a 25.6% increase from $39.8 million the fourth quarter of 2012.
Net income available to common shareholders increased to $36.1 million in the fourth quarter of 2013 as compared to $9.2 million in the third quarter of 2013 and $5.3 million in the fourth quarter of 2012. Excluding the gain from the sale of assets, Birchcliff had net income available to common shareholders of $10.8 million in the fourth quarter of 2013.
Operating costs per boe (excluding transportation and marketing costs) were $5.44 per boe, down 3.9% from $5.66 per boe in the third quarter of 2013 and down 7.5% from $5.88 per boe in the fourth quarter of 2012. This reduction in operating costs on a per boe basis was largely due to the cost benefits achieved from processing increased volumes of natural gas through the PCS Gas Plant and implementation of various optimization initiatives.
In November 2013, Birchcliff made a strategic disposition of non-core assets in the Progress area for $54.7 million, net of adjustments. The transaction included approximately 520 boe per day of Doe Creek light oil production, 2.7 million boe of proved reserves and 4.5 million boe of proved plus probable reserves. This transaction resulted in a financial gain of $33.8 million, $25.3 million net of tax.
Capital expenditures in the fourth quarter were $73.0 million, $18.2 million net of dispositions.
Drilling activities during the fourth quarter of 2013 resulted in 12 (11.5 net) wells, being 7 (7.0 net) natural gas wells and 5 (4.5 net) oil wells. The seven natural gas wells were all Montney/Doig horizontal natural gas wells. The oil wells included 4 (4.0 net) Charlie Lake horizontal light oil wells and 1 (0.5 net) Halfway horizontal light oil well. All the horizontal wells drilled in the fourth quarter of 2013 utilized the latest advancements in multi-stage fracture stimulation technology.
2013 INDEPENDENT RESERVES EVALUATION
Deloitte LLP ("Deloitte"), independent qualified reserves evaluators of Calgary, Alberta, prepared a Reserves Estimation and Economic Evaluation effective December 31, 2013 in respect of Birchcliff's oil and natural gas properties, which is contained in a report dated February 5, 2014 (the "2013 Reserves Evaluation"). Deloitte also prepared reserves estimations and economic evaluations effective December 31, 2012 (the "2012 Reserves Evaluation") and December 31, 2011. Reserves estimates stated herein as at December 31, 2013, 2012 and 2011 are extracted from the relevant evaluation. The 2013 Reserves Evaluation and the prior reserves evaluations have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101").
At December 31, 2013, Deloitte estimated that Birchcliff had 370.1 MMboe of proved plus probable reserves and 220.0 MMboe of proved reserves. Birchcliff's proved plus probable reserves are comprised of 86.5% natural gas and 13.5% light oil and natural gas liquids.
Reserves Summary
The following table summarizes Deloitte's estimates of Birchcliff's working interest oil and natural gas reserves at December 31, 2013 and December 31, 2012, using the Deloitte forecast price assumptions in effect at the applicable reserves evaluation date.
| Summary of Oil and Natural Gas Reserves(1) | Dec 31, 2013 (MMboe) |
Dec 31, 2012 (MMboe) |
Change from Dec 31, 2012 |
| Proved Developed Producing | 62.0 | 54.6 | +13.6% |
| Total Proved | 220.0 | 186.0 | +18.3% |
| Probable | 150.0 | 131.8 | +13.8% |
| Total Proved Plus Probable | 370.1 | 317.8 | +16.5% |
| (1) | Numbers may not total due to rounding |
Net Present Value of Future Net Revenue
The following table is a summary of the net present value of future net revenue associated with Birchcliff's reserves at December 31, 2013 before deducting future income tax expense, and calculated at various discount rates. The net present value of future net revenue attributable to the Corporation's reserves is based on Deloitte's December 31, 2013 forecast price assumptions of commodity prices, which can be found at http://www.ajmdeloitte.ca/price-forecasts.html.
| Net Present Value of Future Net Revenue Before Income Taxes(1)(2)(3) | |||||||
| Discounted At | |||||||
| (Forecast Prices and Costs)(MM$)(per year) | 0% | 5% | 8% | 10% | 15% | 20% | |
| Proved | |||||||
| Developed Producing | 1,643.7 | 1,220.0 | 1,057.3 | 972.2 | 813.3 | 703.9 | |
| Developed Non-producing | 255.5 | 188.6 | 161.8 | 147.5 | 120.1 | 101.0 | |
| Undeveloped | 3,175.8 | 1,725.2 | 1,220.5 | 971.9 | 544.0 | 284.0 | |
| Total Proved | 5,074.9 | 3,133.8 | 2,439.6 | 2,091.5 | 1,477.5 | 1,088.9 | |
| Probable | 4,920.2 | 2,191.2 | 1,437.3 | 1,106.8 | 606.7 | 350.2 | |
| Total Proved Plus Probable | 9,995.2 | 5,325.0 | 3,876.9 | 3,198.3 | 2,084.1 | 1,439.1 | |
| (1) | Estimates of future net revenue, whether discounted or not, do not represent fair market value. |
| (2) | Future net revenue is after deduction of estimated costs of abandonment of existing and future wells and reclamation of future wells and does not include costs of abandonment of facilities, reclamation of facilities and reclamation of existing wells. |
| (3) | Numbers may not total due to rounding. |
The natural gas price forecast used by Deloitte in the 2013 Reserves Evaluation for the years 2014 through 2018 is approximately $0.26 per MMbtu lower than the forecast used by Deloitte for the same period in its 2012 Reserves Evaluation. Notwithstanding the natural gas price forecast for these years decreased by 6%, the net present value of the proved developed producing reserves (at a 10% discount rate) increased by 17.2% as a result of increased reserves volumes, increased oil prices and reduced operating costs recognized in the 2013 Reserves Evaluation.
From the 2013 Reserves Evaluation to the 2012 Reserves Evaluation, Birchcliff had:
- 190% reserve replacement on a proved developed producing basis. Birchcliff added 1.90 boe of proved developed producing reserves for each boe that was produced and sold during the year (calculated by dividing 2013 proved developed producing reserves additions before production, acquisition and dispositions by total production in 2013).
- 486% reserve replacement on a proved basis. Birchcliff added 4.86 boe of proved reserves for each boe that was produced or sold during the year (calculated by dividing 2013 proved reserves additions before production, acquisition and dispositions by total production in 2013).
- 692% reserve replacement on a proved plus probable basis. Birchcliff added 6.92 boe of proved plus probable reserves for each boe that was produced or sold during the year (calculated by dividing 2013 proved plus probable reserves additions before production, acquisition and dispositions by total production in 2013).
Reserves on the Montney/Doig Natural Gas Resource Play
Deloitte estimated at December 31, 2013, Birchcliff had 319.2 MMboe of proved plus probable reserves attributed to horizontal wells on the Montney/Doig Natural Gas Resource Play. This is an increase of 20% from 266.8 MMboe proved plus probable reserves attributed to horizontal wells on the Montney/Doig Natural Gas Resource Play at December 31, 2012.
The following tables summarize Deloitte's estimates of reserves attributable to Birchcliff's horizontal wells on the Montney/Doig Natural Gas Resource Play, the number of horizontal wells to which reserves were attributed and the future capital associated with such reserves.
| Montney/Doig Natural Gas Resource Play Reserves Data(1) | ||||||||||||
| Natural Gas |
Oil and Natural Gas Liquids |
Total | Existing Horizontal Wells and Future Horizontal Well Locations |
Net Future Capital |
||||||||
| (Bcf) | (Mbbl) | (Mboe) | Gross | Net | (MM$) | |||||||
| 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013(2) | 2012 | |
| Proved Developed Producing | 291.6 | 241.0 | 1,940.6 | 1,334.9 | 50,538.1 | 41,493.6 | 117 | 93 | 105.2 | 80.8 | 1.25 | 0 |
| Total Proved | 1,113.0 | 907.6 | 8,202.1 | 5,243.2 | 193,704.5 | 156,509.7 | 384 | 325 | 330.9 | 272.7 | 1,306.1 | 1,129.4 |
| Total Proved Plus Probable | 1,828.0 | 1,541.6 | 14,550.3 | 9,922.2 | 319,214.6 | 266,848.4 | 549 | 472 | 470.8 | 397.5 | 2,146.2 | 1,849.9 |
| (1) | Estimates of reserves and future net revenue for reserves relating to individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation. |
| (2) | Includes approximately $68.2 million of capital for the expansion of the PCS Gas Plant to 240 MMcf per day of total capacity, together with the related gathering pipelines, sales pipeline expansion and compression, plus $32.2 million of capital for the expansion of the PCS Gas Plant to 270 MMcf of total capacity. |
| Montney/Doig Land and Horizontal Well Data | Dec 31, 2013 | Dec 31, 2012 | Dec 31, 2011 | |||
| Gross | Net | Gross | Net | Gross | Net | |
| Number of sections to which Deloitte attributed proved plus probable reserves | 131.6 | 115.2 | 114.3 | 98.3 | 98.5 | 83.4 |
| For existing and future horizontal wells, number of well locations to which Deloitte attributed proved plus probable reserves | 549 | 470.8 | 472 | 397.5 | 425 | 352.7 |
| For existing and future horizontal wells, average number of net well locations per net section to which Deloitte attributed proved plus probable reserves | 4.1(1) | 4.1 | 4.2 | |||
| For existing horizontal wells, average remaining recoverable proved plus probable reserves attributed by Deloitte, plus cumulative production | 4.9 Bcfe | 4.8 Bcfe | 4.3 Bcfe | |||
| For future horizontal wells, average remaining recoverable proved plus probable reserves attributed by Deloitte | 4.2 Bcfe | 4.1 Bcfe | 4.0 Bcfe | |||
| Average cost per well, forecast by Deloitte | $5.2 million | $5.2 million | $4.8 million | |||
| (1) | Currently, for existing and future horizontal wells, the average number of net well locations per net section to which Deloitte attributed proved plus probable reserves is 3.2 for the Basal Doig/Upper Montney Play and 2.9 for the Middle/Lower Montney Play. |
Deloitte has attributed Montney/Doig proved plus probable reserves to 131.6 (115.2 net) sections of land. Drilling success during 2013 in the Middle/Lower Montney Play has resulted in significant reserve assignments by Deloitte to 106.6 (92.5 net) sections of land, an increase of 17.5 net sections of land from 2012. Deloitte has attributed reserves in the Basal Doig/Upper Montney Play to 78.2 (65.3 net) sections of land. There are now 53.2 (42.6 net) sections to which Deloitte has attributed reserves to both the Basal Doig/Upper Montney Play and the Middle/Lower Montney Play.
Management believes that the ultimate recovery from the Corporation's Montney/Doig horizontal natural gas wells will continue to improve year over year as production declines continue to flatten. In addition, as drilling and completion technologies continue to improve, recovery factors and production rates in this unconventional reservoir should also improve.
Reserves on the Worsley Charlie Lake Light Oil Resource Play
At December 31, 2013, Deloitte estimated that in the Worsley Charlie Lake light oil pool on the Worsley Charlie Lake Light Oil Resource Play, Birchcliff had 38.9 MMboe proved plus probable reserves and 19.6 MMboe of proved reserves. This continues the growth trend for Birchcliff's Worsley Charlie Lake reserves since July 1, 2007 (being the effective date of the acquisition of this property), when recoverable reserves were estimated at 15.1 MMboe on a proved plus probable basis and 11.3 MMboe on a proved basis. Both the original oil in place and the estimated recoverable reserves continue to grow and Birchcliff is pleased to report that the Worsley Charlie Lake light oil pool continues to be a top quality asset.
| History of Reserves Estimated for the Worsley Charlie Lake Pool (MMboe)(1) | ||||||||
| Dec 31, 2013 |
Dec 31, 2012 |
Dec 31, 2011 |
Dec 31, 2010 |
Dec 31, 2009 |
Dec 31, 2008 |
Dec 31, 2007 |
July 1, 2007 |
|
| Proved | 19.6 | 19.6 | 18.8 | 18.8 | 18.3 | 17.5 | 15.0 | 11.3 |
| Proved Plus Probable | 38.9 | 34.7 | 31.3 | 28.2 | 26.3 | 24.6 | 21.2 | 15.1 |
| (1) | Estimates of reserves relating to individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. |
2013 FINDING AND DEVELOPMENT COSTS
During 2013, Birchcliff's finding and development ("F&D") costs were $268.1 million and its finding, development and acquisition ("FD&A") costs were $213.8 million. The following table sets forth Birchcliff's estimates of its F&D costs per boe and FD&A costs per boe, excluding future development capital and including future development capital, on a proved and proved plus probable basis.
| Finding and Development Costs ($/boe)(1) | |||||||||
| Excluding Future Development Capital | 2013 | 2012 | 2011 | Three Year Average | |||||
| F&D - Proved | $ | 5.85 | $ | 7.77 | $ | 4.77 | $ | 6.00 | |
| F&D - Proved Plus Probable | $ | 4.11 | $ | 6.09 | $ | 2.88 | $ | 4.08 | |
| Acquisitions - Proved | - | $ | 10.96 | $ | 732.34 | $ | 13.74 | ||
| Acquisitions - Proved Plus Probable | $ | 0.79 | $ | 3.38 | $ | 36.11 | $ | 3.87 | |
| Dispositions - Proved | $ | 23.90 | $ | 9.71 | $ | 6.31 | $ | 14.13 | |
| Dispositions - Proved Plus Probable | $ | 13.32 | $ | 4.36 | $ | 3.69 | $ | 7.23 | |
| Total FD&A - Proved(2) | $ | 4.91 | $ | 7.83 | $ | 4.85 | $ | 5.74 | |
| Total FD&A - Proved Plus Probable(2) | $ | 3.46 | $ | 5.89 | $ | 2.92 | $ | 3.87 | |
| Including Future Development Capital(3) | |||||||||
| F&D - Proved | $ | 9.39 | $ | 11.10 | $ | 13.15 | $ | 11.28 | |
| F&D - Proved Plus Probable | $ | 9.03 | $ | 11.99 | $ | 12.01 | $ | 11.02 | |
| Acquisitions - Proved | - | $ | 17.78 | $ | 732.34 | $ | 20.54 | ||
| Acquisitions - Proved Plus Probable | $ | 23.21 | $ | 9.61 | $ | 36.11 | $ | 11.10 | |
| Dispositions - Proved | $ | 30.42 | $ | 19.80 | $ | 6.31 | $ | 20.65 | |
| Dispositions - Proved Plus Probable | $ | 17.56 | $ | 12.71 | $ | 3.69 | $ | 12.57 | |
| Total FD&A - Proved(2) | $ | 8.29 | $ | 10.91 | $ | 13.47 | $ | 10.99 | |
| Total FD&A - Proved Plus Probable(2) | $ | 8.60 | $ | 11.56 | $ | 12.31 | $ | 10.93 | |
| (1) | See advisories for an explanation of the methodology used to calculate F&D costs. |
| (2) | Based upon FD&A costs, net of disposition proceeds, and reserve additions, net of reserves disposed of. |
| (3) | Includes the increase in future development capital for 2013 over 2012 of $147.1 million on a proved basis and $316.7 million on a proved plus probable basis. |
Deloitte's estimates of future development costs are $1.45 billion on a proved basis and $2.50 billion on a proved plus probable basis, which includes approximately $100.4 million for the expansion of the PCS Gas Plant to 270 MMcf per day of total capacity, together with the related gathering pipelines, sales pipeline expansion and compression. The increase in future development capital for 2013 over 2012 is $147.1 million on a proved basis and $316.7 million on a proved plus probable basis.
Both the 2013 Reserves Evaluation and the 2012 Reserves Evaluation included, on average, $5.2 million for each future Montney/Doig horizontal natural gas well to which reserves were assigned, which includes drill, case, complete and tie-in costs.
2013 RECYCLE RATIOS
The following table shows Birchcliff's recycle ratio for operating and funds flow netback, which are calculated in each case by dividing the average operating netback per boe or funds flow netback per boe, as the case may be, by each of the F&D costs and the FD&A costs.
| Recycle Ratios(1) | Operating Netback Recycle Ratio |
Funds Flow Netback Recycle Ratio | |||
| 2013 | 2012 | 2013 | 2012 | ||
| Excluding Future Development Capital | |||||
| F&D - Proved Plus Probable | 5.5 | 3.2 | 4.5 | 2.4 | |
| FD&A - Proved Plus Probable | 6.5 | 3.3 | 5.3 | 2.4 | |
| Including Future Development Capital | |||||
| F&D - Proved Plus Probable | 2.5 | 1.6 | 2.0 | 1.2 | |
| FD&A - Proved Plus Probable | 2.6 | 1.7 | 2.2 | 1.2 | |
| (1) | See advisories for the methodology used in the calculation of F&D costs used in these recycle ratios. |
During 2013, the average WTI price of crude oil was US $97.97 per barrel and the average price of natural gas at AECO was Cdn $3.17 per Mcf. Operating netback per boe for 2013 was $22.53. Funds flow netback per boe for 2013 was $18.50.
2013 INDEPENDENT MONTNEY/DOIG NATURAL GAS RESOURCE ASSESSMENT
Deloitte conducted an independent review and audit of resources, effective December 31, 2013, in respect of Birchcliff lands that have potential for the Montney/Doig Natural Gas Resource Play, which is contained in a report dated February 6, 2014 (the "2013 Resource Assessment"). Deloitte also prepared a resource assessment effective December 31, 2012 (the "2012 Resource Assessment"). The 2013 Resource Assessment and 2012 Resource Assessment have been prepared in accordance with the standards contained in the COGE Handbook and NI 51-101.
Resource estimates stated herein as at December 31, 2013 and 2012 are extracted from the relevant evaluation and reflect only Birchcliff's working interest share of resources for its lands in the area covered by the resource assessment (the "Study Area"). The resource assessment does not include Birchcliff's Worsley Charlie Lake Light Oil Resource Play or any of Birchcliff's other properties.
Montney/Doig Natural Gas Resource Assessment Summary
The following table summarizes Deloitte's estimates of Birchcliff's natural gas resources on the Montney/Doig Natural Gas Resource Play at December 31, 2013 and December 31, 2012, on a best estimate case.
| Best Estimate Case | |||
| Summary of Montney/Doig Natural Gas Resources | Dec 31, 2013 (Bcfe) |
Dec 31, 2012 (Bcfe) |
Change from Dec 31, 2012 |
| Total Petroleum Initially In Place ("PIIP") | 52,036.4 | 39,709.5 | +31.0% |
| Total Undiscovered PIIP(1) | 34,443.3 | 26,331.8 | +30.8% |
| Prospective Resources | 15,809.9 | 13,003.3 | +21.6% |
| Total Discovered PIIP(1) | 17,593.2 | 13,377.7 | +31.5% |
| Contingent Resources | 6,547.8 | 4,869.1 | +34.5% |
| (1) | See the advisories with respect to discovered and undiscovered resources. |
Compared to the 2012 Resource Assessment, the best estimate of total PIIP has grown from 39.7 Tcfe to 52.0 Tcfe, a 31% increase. Additionally, Birchcliff was very successful with its strategy to promote resources from undiscovered to discovered in 2013 through its exploration program. Discovered PIIP increased 31.5% from the 2012 Resource Assessment, from 13.4 Tcfe to 17.6 Tcfe. Compared to the 2012 Resource Assessment, the best estimate of contingent resources has grown from 4.9 Tcfe to 6.5 Tcfe, a 35% increase. These increases are a result of land acquisitions and drilling.
Background to the Montney/Doig Natural Gas Resource Assessment
Birchcliff holds significant high working interest acreage in large contiguous blocks on the Montney/Doig Natural Gas Resource Play in the Peace River Arch area of Alberta. Birchcliff's lands are proximal to our PCS Gas Plant and to third party gathering and processing infrastructure.
The Study Area assessed by Deloitte is comprised of the Doig Phosphate, Basal Doig, and Montney formations in the greater Pouce Coupe, Elmworth, Sinclair and Bezanson areas of the Peace River Arch region of Alberta, ranging from Townships 69 to 81, Ranges 2 to 13W6. The Study Area is bounded in a northwest - southeast direction by the Montney/Doig deep basin edges and covered a total of 340.5 gross sections of land held by Birchcliff at December 31, 2013, which includes:
- 328.0 (306.0 net) sections, with a 93.3% working interest, which have potential for the Middle/Lower Montney Play; and
- 307.3 (283.9 net) sections, with a 92.4% working interest, which have potential for the Basal Doig/Upper Montney Play.
Birchcliff's total land holdings on the two plays described above are 635.3 (589.9 net) sections. On full development of four horizontal wells per section per play, Birchcliff has 2,359.6 net horizontal drilling locations. With 117 (105.2 net) horizontal locations drilled at the end of 2013, there remain 2,254.4 net future horizontal drilling locations.
Deloitte utilized probabilistic methods to generate high, best, and low estimates of reserves and resources volumes. Results from the 2013 Resource Assessment are presented in the following table for Birchcliff's working interest share of gross volumes. Proved, proved plus probable and proved plus probable plus possible reserves determined by the 2013 Reserves Evaluation are included in this table for completeness, however reserves were not the focus of the 2013 Resource Assessment.
| Summary of Birchcliff Reserves and Resources(1)(2) | ||||||
| Resource Class | Reserves and Resource Volumes(Bcfe) | |||||
| Low Estimate Case | Best Estimate Case | High Estimate Case | ||||
| Discovered | Cumulative Production(3) | 130.7 | 130.7 | 130.7 | ||
| Remaining Reserves(3)(4) | 1,163.5 | 1,912.5 | 2,792.1 | |||
| Surface Loss/Shrinkage | 66.2 | 104.6 | 149.9 | |||
| Total Commercial | 1,360.4 | 2,147.8 | 3,072.7 | |||
| Contingent Resources | 4,456.0 | 6,547.8 | 9,961.1 | |||
| Unrecoverable(5) | 7,147.5 | 8,897.6 | 11,027.4 | |||
| Total Sub-commercial | 11,603.5 | 15,445.3 | 20,988.5 | |||
| Total Discovered PIIP | 12,964.0 | 17,593.2 | 24,061.2 | |||
| Undis-covered | Prospective Resources | 10,168.6 | 15,809.6 | 24,619.8 | ||
| Unrecoverable(5) | 16,273.4 | 18,633.7 | 20,888.1 | |||
| Total Undiscovered PIIP | 26,442.0 | 34,443.3 | 45,507.9 | |||
| Total Petroleum Initially In Place (PIIP) | 39,406.0 | 52,036.4 | 69,569.1 | |||
| Notes: | |
| (1) | All reserves and resources are gross volumes at December 31, 2013, which are equal to Birchcliff's working interest share before deduction of royalties and without including any royalties held by Birchcliff. |
| (2) | Numbers may not total due to rounding. |
| (3) | Sales gas and related natural gas liquids. |
| (4) | Includes reserves assigned to both vertical and horizontal Montney/Doig wells. The best estimate reflects the estimate of proved plus probable reserves contained in the 2013 Reserves Evaluation. The low estimate reflects the estimate of proved reserves contained in the 2013 Reserves Evaluation. The high estimate reflects the estimate of proved plus probable plus possible reserves contained in the 2013 Reserves Evaluation. |
| (5) | Unrecoverable includes surface loss/shrinkage on volumes of contingent resources and prospective resources. The unrecoverable portion of Undiscovered PIIP is those quantities determined not to be recoverable by future development projects. A portion of these resources may become recoverable in the future as commercial circumstances change or technological developments occur, but the remaining portion may never be recovered due to physical and/or chemical constraints of the reservoir rock and the fluid within it. |
2014 STRATEGIC ACQUISITION OF PARTNER'S INTEREST
Birchcliff completed a strategic acquisition on January 15, 2014, with an effective date of January 1, 2014, where Birchcliff bought a partner's 30% working interest in land and production in the Pouce Coupe area. The acquisition included 38 (11.3 net) sections of land on the Montney/Doig Natural Gas Resource Play and 9.6 MMcfe per day (1,600 boe per day) of Birchcliff operated production, the majority of which is processed at our PCS Gas Plant. This transaction has allowed Birchcliff to consolidate lands it formerly held at a 70% working interest with lands it holds at 100% working interest, allowing for a contiguous development plan, eliminating holding buffers and increasing flexibility of capital allocation. By extrapolation from the reserves assigned by Deloitte at December 31, 2013 to the lands held at 70% working interest, the 30% working interest acquired represents additional reserves as follows.
| Reserves Acquired January 15, 2014(1) | (MMboe) | ||
| Proved Developed Producing | 5.4 | ||
| Total Proved | 26.9 | ||
| Probable | 13.9 | ||
| Total Proved Plus Probable | 40.8 |
| (1) | Estimates of reserves relating to individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. |
Reserve Life Index
Birchcliff's reserve life index is 34.1 years on a proved plus probable basis and 20.5 years on a proved basis, in each case using reserves estimates by Deloitte at December 31, 2013 plus the reserves added in the strategic acquisition of a partner's interest on January 15, 2014 and assuming an average daily production rate of 33,000 boe per day.
THANK YOU TO THE BIRCHCLIFF TEAM
We are very pleased and excited with the current and future outlook for Birchcliff. Our production, reserves and opportunity portfolio continues to increase while our cost structure continues to decrease. Focus, low cost operations and financial flexibility has positioned Birchcliff to execute its long term strategy.
Birchcliff's 2013 results were achieved thanks to the dedication and hard work of our talented team.
We thank Mr. Seymour Schulich, our largest shareholder, holding 40 million common shares, representing 27.8% of the current issued and outstanding common shares. Mr. Schulich provides phenomenal financial support and, more importantly, has never wavered from his commitment to our Management Team, whether the natural gas price is high or low. He provides continuous feedback and shrewd advice, which is always delivered with a little humor! Mr. Schulich is a major part of the Birchcliff Team.
On behalf of our Management Team and Directors, I thank all of our employees for their hard work and dedication to the achievement of our corporate goals.
Thank you to all our shareholders for their continued support and their trust in all of us at Birchcliff.
We look forward to another excellent year.
A. Jeffery Tonken, President and Chief Executive Officer
DEFINITIONS OF OIL AND GAS RESOURCES AND RESERVES
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources as follows:
| Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate. | |
| Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate. | |
| High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate. |
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable.
Reserves are classified according to the degree of certainty associated with the estimates:
| Proved Reserves are 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. | |
| Probable Reserves are 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. | |
| Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. |
Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "total Petroleum Initially-In-Place". Resources are classified in the following categories:
| Total Petroleum Initially-In-Place ("PIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. | |
| Discovered Petroleum Initially-In-Place is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable. | |
| 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. | |
| Undiscovered Petroleum Initially-In-Place is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable." | |
| Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. | |
| Unrecoverable is that portion of Discovered and Undiscovered PIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. | |
| Production is the cumulative quantity of petroleum that has been recovered at a given date. |
ADVISORIES
Non-GAAP Measures: This Press release uses "funds flow", "funds flow from operations", "funds flow netback", "funds flow per common share", "netback", "operating netback", "estimated operating netback", "operating margin" and "total cash costs", which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable measures to other companies where similar terminology is used. Netback denotes petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses. Estimated operating netback is based upon certain cost allocations and accruals directly related to the PCS Gas Plant and related wells and infrastructure on a production month basis. Funds flow, funds flow netback or funds flow from operations denotes cash flow from operating activities as it appears on the Corporation's Condensed Statements of Cash Flows before decommissioning expenditures and changes in non-working capital. Funds flow, funds flow netback or funds flow from operations is also derived from net income plus income tax expense (less any recovery), depletion, depreciation and accretion expense, stock-based compensation expense, amortization of deferred financing fees, unrealized losses on financial instruments (less unrealized gains), losses on divestitures (less gains on divestitures) and dividends paid on Series C Preferred Shares. Funds flow per common share denotes funds flow divided by the weighted average number of basic or diluted common shares. Operating margin is calculated by dividing the estimated operating netback for the period by the petroleum and natural gas revenue for the period.
Boe Conversions: Barrel of oil equivalent ("boe") amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel of oil (1 bbl). Boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Mcfe, MMcfe, Bcfe and Tcfe Conversions: Thousands of cubic feet of gas equivalent ("Mcfe"), millions of cubic feet of gas equivalent ("MMcfe" billions of cubic feet of gas equivalent), ("Bcfe") and trillions of cubic feet of gas equivalent ("Tcfe") amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas. Mcfe, MMcfe, Bcfe and Tcfe amounts may be misleading, particularly if used in isolation. A conversion ratio of 1 bbl to 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
MMbtu Pricing Conversion: $1.00 per MMbtu equals $1.00 per Mcf based on a standard heat value Mcf.
Reserves for Portion of Properties: With respect to the disclosure of reserves contained herein relating to portions of the Corporation's properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation.
Finding and Development Costs: With respect to disclosure of finding and development costs disclosed in this Press Release:
- The amounts of finding and development and/or acquisition costs contained in the table and the disclosure set forth above for each of the years 2011, 2012 and 2013 are calculated by dividing the total of the net amount of the particular costs noted in each line incurred during such year by the amounts of additions to total proved reserves and total proved plus probable reserves during such year that resulted from the expenditure of such costs.
- In calculating the amounts of finding and development and/or acquisition costs for a year, the changes during the year in estimated future development costs and in estimated reserves are based upon the evaluations of Birchcliff's reserves prepared by Deloitte, or their predecessor, effective December 31 of such year.
- The aggregate of the exploration and development costs incurred in the most recent financial year and any change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Discovered Resources: With respect to the discovered resources (including contingent resources) described in this Press Release, there is no certainty that it will be commercially viable to produce any portion of the resources.
Undiscovered Resources: With respect to the undiscovered resources (including prospective resources) described in this Press Release, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Forward-Looking Information: This Press Release contains forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking information relates to future events or future performance and is based upon the Corporation's current internal expectations, estimates, projections, assumptions and beliefs. All information other than historical fact is forward-looking information. Information relating to reserves and resources is forward-looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves and resources exist in the quantities estimated and that they will be commercially viable to produce in the future. Words such as "plan", "expect", "project", "intend", "believe", "anticipate", "estimate", "may", "will", "potential", "proposed" and other similar words that convey certain events or conditions "may" or "will" occur are intended to identify forward-looking information. In particular, this Press Release contains forward-looking information relating to estimates of recoverable reserves and resource volumes; planned production increases, planned 2014 capital spending and sources of funding; and the intention to drill and complete future wells.
The forward-looking information is based upon assumptions as to future commodity prices, currency exchange rates, inflation rates, well production rates, well drainage areas, success rates for future drilling and availability of labour and services. With respect to estimates of reserves and resource volumes, a key assumption is the validity of the data used by Deloitte in their independent reserves evaluation and resource assessments. With respect to numbers of future wells to be drilled, a key assumption is that geological and other technical interpretations performed by the Corporation's technical staff, which indicate that commercially economic volumes can be recovered from the Corporation's lands as a result of drilling future wells, are valid. Estimates as to 2014 first quarter production and 2014 exit production assumes that no unexpected outages occur in the infrastructure that the Corporation relies on to produce its wells, that existing wells continue to meet production expectations and any future wells, scheduled to come on production in 2014 meet timing and production expectations.
Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. Although the Corporation believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. As a consequence, actual results may differ materially from those anticipated.
Forward-looking information necessarily involves both known and unknown risks associated with oil and gas exploration, production, transportation and marketing such as uncertainty of geological and technical data, imprecision of reserves and resource estimates, operational risks, environmental risks, loss of market demand, general economic conditions affecting ability to access sufficient capital, changes in governmental regulation of the oil and gas industry and competition from others for scarce resources.
The foregoing list of risk factors is not exhaustive. Additional information on these and other risk factors that could affect operations or financial results are included in the Corporation's most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities. Forward-looking information is based on estimates and opinions of management at the time the information is presented. The Corporation is not under any duty to update the forward-looking information after the date of this Press Release to conform such information to actual results or to changes in the Corporation's plans or expectations, except as otherwise required by applicable securities laws.
Birchcliff is a Calgary, Alberta based intermediate oil and gas company with operations concentrated within its one core area, the Peace River Arch of Alberta. Birchcliff's Common Shares; Cumulative Redeemable Preferred Shares, Series A; Cumulative Redeemable Preferred Shares, Series C; and Warrants are listed for trading on the Toronto Stock Exchange under the symbols "BIR", "BIR.PR.A", "BIR.PR.C" and "BIR.WT" respectively.
Contact Information:
Jeff Tonken
President and Chief Executive Officer
(403) 261-6401
(403) 261-6424 (FAX)
Birchcliff Energy Ltd.
Bruno Geremia
Vice-President and Chief Financial Officer
(403) 261-6401
(403) 261-6424 (FAX)
Birchcliff Energy Ltd.
Jim Surbey
Vice-President, Corporate Development
(403) 261-6401
(403) 261-6424 (FAX)
www.birchcliffenergy.com