CALGARY, ALBERTA--(Marketwired - March 31, 2014) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) announces its operating and financial results for the fourth quarter and year ended December 31, 2013.
HIGHLIGHTS
- Anderson commenced a Cardium horizontal light oil winter drilling program using slick water frac technology in November 2013. The average initial production rate over the first 30 days for the first five wells in the program was 458 BOED per well. The best performing well from this winter's drilling program averaged 697 bpd of oil, 755 bpd of oil and NGL and 1,119 BOED in its first 30 days of production.
- The Company closed all previously announced property dispositions prior to year end. Approximately $80 million in properties were sold during 2013.
- In October 2013, the Company repaid its bank debt, finalized a new revolving production loan facility for $28 million and concluded its strategic alternatives review process.
- Production in the fourth quarter of 2013 was 2,448 BOED. Net of production from the sold properties, the Company produced 2,112 BOED, of which 26% was oil and NGL. The Company estimates 2014 production of approximately 2,600 BOED (33% oil and NGL).
- Proved plus probable ("P&P") BOE reserves were 8.8 MMBOE at December 31, 2013.
- Cardium P&P reserves were 5.3 MMBOE representing 60% of total P&P reserves volumes and 80% of total P&P reserves value on a pre-tax 10% net present value ("NPV 10") basis.
- Oil and NGL represent 29% of the Company's proved developed producing ("PDP") reserves, 36% of total proved ("TP") reserves and 42% of P&P reserves on a BOE basis.
- Anderson's total P&P pre-tax NPV 10 reserves value at December 31, 2013 was $100.3 million. Undeveloped land has been valued at $3.4 million.
- 118 gross (74.7 net) light oil horizontal drilling locations have been identified. Only 25% of the net locations are recognized as P&P locations in the year end reserve report. Approximately 97% of the net locations are Company operated.
FINANCIAL AND OPERATING HIGHLIGHTS
| | Three months ended December 31 | | Year ended December 31 | |
| (thousands of dollars, unless otherwise stated) | | 2013 | | | 2012 | | %
Change | | | 2013 | | | 2012 | | %
Change | |
| Oil and gas sales (1) | $ | 8,217 | | $ | 15,274 | | (46% | ) | $ | 53,983 | | $ | 77,806 | | (31% | ) |
| Revenue, net of royalties (1) | $ | 7,288 | | $ | 13,796 | | (47% | ) | $ | 48,850 | | $ | 69,815 | | (30% | ) |
| Funds from operations (2) | $ | (306 | ) | $ | 5,694 | | (105% | ) | $ | 11,289 | | $ | 29,641 | | (62% | ) |
| Funds from operations per share | | | | | | | | | | | | | | | | |
| | Basic and diluted (2) | $ | - | | $ | 0.03 | | (100% | ) | $ | 0.07 | | $ | 0.17 | | (59% | ) |
| Adjusted loss before taxes (3) | $ | (2,745 | ) | $ | (11,799 | ) | 23% | | $ | (17,386 | ) | $ | (21,738 | ) | 33% | |
| Adjusted loss before taxes per share(3) | | | | | | | | | | | | | | | | |
| | Basic and diluted | $ | 0.02 | | $ | (0.07 | ) | 100% | | $ | (0.10 | ) | $ | (0.13 | ) | 25% | |
| Loss | $ | (2,445 | ) | $ | (8,895 | ) | 73% | | $ | (105,601 | ) | $ | (31,493 | ) | (235% | ) |
| Loss per share | | | | | | | | | | | | | | | | |
| | Basic and diluted | $ | (0.01 | ) | $ | (0.05 | ) | 80% | | $ | (0.61 | ) | $ | (0.18 | ) | (239% | ) |
| Capital expenditures (net of proceeds on dispositions) | $ | (71,972 | ) | $ | (26,880 | ) | (168% | ) | $ | (63,895 | ) | $ | (38,990 | ) | (64% | ) |
| Working capital (deficiency) (2) | | | | | | | | | $ | 9,682 | | $ | (64,531 | ) | 115% | |
| Convertible debentures | | | | | | | | | $ | 88,922 | | $ | 86,753 | | 3% | |
| Shareholders' equity | | | | | | | | | $ | 28,179 | | $ | 132,960 | | (79% | ) |
| Average shares outstanding (thousands): | | | | | | | | | | | | | | | | |
| | Basic & Diluted | | 172,550 | | | 172,550 | | - | | | 172,550 | | | 172,550 | | - | |
| Ending shares outstanding (thousands) | | | | | | | | | | 172,550 | | | 172,550 | | - | |
| Average daily sales: | | | | | | | | | | | | | | | | |
| | Oil (bpd) | | 537 | | | 1,135 | | (53% | ) | | 1,059 | | | 1,507 | | (30% | ) |
| | NGL (bpd) | | 166 | | | 338 | | (51% | ) | | 237 | | | 591 | | (60% | ) |
| | Natural gas (Mcfd) | | 10,467 | | | 18,159 | | (42% | ) | | 13,227 | | | 23,878 | | (45% | ) |
| | Barrels of oil equivalent (BOED) (4) | | 2,448 | | | 4,500 | | (46% | ) | | 3,500 | | | 6,078 | | (42% | ) |
| Average prices: | | | | | | | | | | | | | | | | |
| | Oil ($/bbl) | $ | 84.26 | | $ | 79.73 | | 6% | | $ | 89.89 | | $ | 83.21 | | 8% | |
| | NGL ($/bbl) | $ | 61.60 | | $ | 52.02 | | 18% | | $ | 55.04 | | $ | 57.20 | | (4% | ) |
| | Natural gas ($/Mcf) | $ | 3.19 | | $ | 3.16 | | 1% | | $ | 2.93 | | $ | 2.21 | | 33% | |
| | Barrels of oil equivalent ($/BOE) (4) | $ | 36.49 | | $ | 36.89 | | (1% | ) | $ | 42.26 | | $ | 34.98 | | 21% | |
| Realized gain (loss) on derivative contracts ($/BOE) (5) | $ | (2.96 | ) | $ | 5.39 | | (155% | ) | $ | (2.75 | ) | $ | 2.44 | | (213% | ) |
| Royalties ($/BOE) | $ | 4.13 | | $ | 3.57 | | 16% | | $ | 4.02 | | $ | 3.59 | | 12% | |
| Operating costs ($/BOE) | $ | 14.31 | | $ | 12.11 | | 18% | | $ | 13.25 | | $ | 10.90 | | 22% | |
| Transportation costs ($/BOE) | $ | 0.28 | | $ | 0.10 | | 180% | | $ | 0.31 | | $ | 0.22 | | 41% | |
| Operating netback ($/BOE) (3)(5) | $ | 14.81 | | $ | 26.50 | | (44% | ) | $ | 21.93 | | $ | 22.71 | | (3% | ) |
| | | | | | | | | | | | | | | | | |
| Reserves (MBOE): (4) | | | | | | | | | | | | | | | | |
| | Total proved | | | | | | | | | | 5,311 | | | 10,297 | | (48% | ) |
| | Total proved plus probable | | | | | | | | | | 8,822 | | | 17,770 | | (50% | ) |
| Wells drilled (gross) | | 3 | | | 4 | | (25% | ) | | 5 | | | 7 | | (29% | ) |
| (1) | Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts. |
| (2) | Funds from operations, funds from operations per share, working capital and working capital (deficiency) are considered additional GAAP measures. Refer to the section entitled "Additional GAAP Measures" in the Management's Discussion and Analysis ("MD&A") for a more complete description of these additional GAAP measures. |
| (3) | Adjusted loss before taxes, adjusted loss before taxes per share and operating netback per BOE are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" in the MD&A for a more complete description of these non-GAAP terms, reconciliations to more closely related GAAP measures, and the purposes for which management uses the non-GAAP measures. These non-GAAP measures may not be comparable with the calculation of similar measures for other entities. |
| (4) | Barrels of oil equivalent ("BOE") may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 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. |
| (5) | Excludes realized loss of $0.2 million related to derivative contracts settled upon the sale of the Garrington and Ferrier Cardium assets. |
COMPLETION OF STRATEGIC REVIEW PROCESS
In October 2013, the Company announced that it had concluded its strategic alternatives review process. Over the prior year and a half, a Special Committee of the Board of Directors had investigated various options to enhance shareholder value, including the sale of the Company. At the conclusion of the process, the Company had achieved the following:
- sold over $150 million in assets;
- reduced bank debt from $106.7 million at March 31, 2012 to nil at December 31, 2013;
- reduced overall debt (defined for this purpose as bank debt plus other working capital before unrealized gains and losses on derivative contracts, plus the face value of convertible debentures) from $230.4 million at March 31, 2012 to $86.3 million at December 31, 2013;
- reduced decommissioning obligations from $59.2 million at March 31, 2012 to $30.4 million at December 31, 2013, and by a further $3.0 million subsequent to year end;
- restructured its shallow gas and Cardium drilling commitments so that by the end of January 2013, the Company had completed all of these drilling commitments;
- demonstrated the improved production performance from slick water fracture stimulation; and
- continued to be an industry leader in keeping drilling and completion costs low in the Cardium horizontal light oil play.
Asset sales during the strategic alternatives process were driven by a desire to reduce bank debt. By the fourth quarter of 2013, bank debt was reduced to zero, the Company had surplus cash and a $28 million unused bank line. The completion of the asset sale in October 2013 ended the strategic alternatives process and forged a new single bank relationship with Alberta Treasury Branches who had been part of the previous three bank syndicate.
STRATEGY
Coming out of the strategic alternatives process, the Company is substantially smaller in terms of production, has cash in the bank and has an unused bank operating line. The Company has also lost its analyst coverage and has an admittedly weak share price. The overall market for public junior oil and gas companies has been very weak in the past 18 months. Although Anderson has no bank debt, it does have convertible debentures maturing in 2016 and 2017. The Company's business plan is to pursue growth of its asset base and cash flow, and increase its financial flexibility to meet its obligations when they become due. A strategy of increasing oil assets, production and cash flow should support a higher borrowing base over time.
The current share price reflects the uncertainty associated with the recently completed strategic alternatives process, the lack of drilling activity during the process and a debt to cash flow ratio that is currently too high. With the bank debt issues resolved, Anderson intends to focus on rebuilding its asset base by drilling Cardium horizontal light oil wells, and growing its Cardium horizontal oil drilling inventory in the Willesden Green, West Pembina and Buck Lake areas. The Company expects it will take time to foster new investor interest in the stock, until it can demonstrate consistent growth in annual oil production. The longer term debenture maturities give the Company time to rebuild its asset base. By resuming a drilling program and controlling the infrastructure in its Cardium oil properties where feasible, the Company should be able to increase oil production and operating netbacks.
Anderson will continue to optimize, rationalize, consolidate and improve the profitability of its shallow gas business. The Company is not planning any significant new investments in the shallow gas business, and may dispose of some or all of the shallow gas assets.
In the fourth quarter of 2013 and the first quarter of 2014, the Company disposed of its unprofitable shallow gas assets. The Company's remaining shallow gas properties are profitable at current natural gas prices.
The Company has no plans to dispose of its Cardium oil assets.
Anderson continues to implement new approaches in Cardium horizontal drilling and completion technology to improve the profitability of its Cardium oil operation. Recent technological changes include repositioning the trajectory of the horizontal well within the Cardium zone to maximize frac effectiveness and using dissolvable frac balls. In 2014, the Company plans to drill its first long reach horizontal oil well that is expected to traverse up to 3,000 metres of horizontal Cardium net pay. It is anticipated that this well will access Cardium reserves in two sections of land as opposed to the current one section of land per horizontal well. There is a capital cost benefit to drilling an extended reach well over two sections as compared to two wells traversing one section of land each. There is also a reserves benefit with longer horizontal wells due to additional reservoir contact.
The goal is to have Cardium wells payout in approximately one year on average. Currently, Anderson has drilled several wells that have or will payout in a year and will continue to focus on driving the average well payout down. The Company operates over 90% of its production and almost all of its drilling operations. Where it can, the Company strives to operate its own oil and gas infrastructure and attract third parties to utilize this infrastructure on a processing fee basis in order to reduce overall operating costs.
Anderson is developing new light oil horizontal plays on its existing acreage in the Mannville and Belly River and is planning to drill one of these plays in the remainder of 2014.
TIMING OF STRATEGY
As a result of the 2012 and 2013 asset dispositions, the financial results for the fourth quarter 2013 and for the year ended December 31, 2013 are not indicative of future operations. The current winter drilling program is expected to have a positive impact on the first and second quarters of 2014, as operating netbacks on Cardium drilling operations were approximately $40 per BOE in the fourth quarter of 2013. The Company drilled 7 gross (7.0 net) wells this winter that are expected to materially add to its production in 2014. The Company will be reviewing its capital program at the end of the first quarter.
WINTER DRILLING PROGRAM
This winter, Anderson embarked on a seven well drilling program. The program started a few weeks later than planned in order to use the same drilling rig that was used last year, which helped to keep drilling costs low. Two of the seven wells in the program were originally planned to be on-stream in late January, however the solution gas from these two wells was destined to go to a third party natural gas plant that suffered a plant outage which lasted almost a month. This outage is now over and these oil wells and their solution gas are on-stream. The other five wells in the program were unaffected by the third party plant outage.
The best performing well from this winter's drilling program averaged 697 bpd of oil, 755 bpd of oil and NGL and 1,119 BOED in its first 30 days of production.
Results from the program to date are shown in table below:
| Average Gross Initial Production for first 30 days (IP 30) (1) | |
| Number of wells in average | 5 |
| Barrels of oil per day (BOPD) | 297 |
| Barrels of oil and NGL per day (BPD) | 320 |
| Barrels of oil equivalent per day (BOED) (2) | 458 |
| (1) | Short term production rates can be influenced by flush production effects from fracture stimulation in horizontal wellbores and may not be indicative of longer term production performance. Individual well performance can vary. |
| (2) | Barrels of oil equivalent ("BOE") may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 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. |
The remaining two wells in the winter program were brought on production late in the first quarter and do not have 30 days of production history. The Company will have IP30 data for all the wells in its winter drilling program by the time it reports its first quarter results for 2014.
The comparable IP 30 data for the slick water drilling programs from last year was 301 bpd of oil, 329 bpd of oil and NGL and 453 BOED for seven wells. Last winter's program included four wells drilled and completed with slick water fracture stimulation in Garrington and Ferrier which were sold in October 2013.
DRILLING AND COMPLETION COSTS
Drilling and completion costs for this year's drilling program averaged $2.3 million per well and were very similar to the prior year.
LIGHT OIL HORIZONTAL DRILLING INVENTORY
The Company's undeveloped light oil horizontal drilling inventory at March 28, 2014, after completion of the winter drilling program, is outlined below:
| Prospect Area (number of drilling locations) | Gross | | Net* |
| Willesden Green Cardium | 84 | | 59.7 |
| West Pembina/Buck Lake Cardium | 26 | | 7.7 |
| Mannville/Belly River | 8 | | 7.3 |
| Total Light Oil Horizontal Drilling Inventory, March 28, 2014 | 118 | | 74.7 |
| * Net is net revenue interest |
GLJ booked undeveloped reserves to 23.3 net locations at December 31, 2013, of which 4.0 net locations were drilled in the first quarter of 2014 and the remaining 19.3 net locations are included in the table above. The locations booked by GLJ include 1.8 net locations related to the Mannville / Belly River prospect area.
Four gross (2.2 net) locations are on lands where the Company's development plan is to drill extended reach horizontal wells traversing two sections of land.
The Company has a potential drilling inventory of 95 gross (58 net) horizontal locations in the Second White Specks light oil play. Offsetting industry activity has not yet proved this play to be commercial and therefore it is not included in the drilling inventory table above.
The Company also has an extensive shallow gas drilling inventory in the Edmonton Sands. At the present time, the Company's business strategy does not include any near term plans for shallow gas drilling.
ACQUISITIONS, DISPOSITIONS AND FARM-INS
As part of the rationalization of its natural gas portfolio, the Company completed two additional property dispositions after the conclusion of the strategic alternatives process.
On November 28, 2013, the Company sold 860 Mcfd of shallow gas production for proceeds of $2.1 million. Approximately 88% of the production from this property was scheduled to be shut-in on December 1, 2013, as the outside operated downstream sales gas system was being converted into a liquids rich high pressure gathering system. Although this property had been profitable when it was producing, the capital cost and time lag required to bring it back on-stream was significant and the Company elected to sell the asset as opposed to spending the additional dollars to resume production. This sale reduced the Company's decommissioning obligation by $1.3 million.
On February 28, 2014, the Company closed a transaction whereby it disposed of 107 wellbores, 31 compressor stations and 880 Mcfd of forecasted 2014 shallow gas production. This property had a historical operating cost of approximately $4.00 per Mcf and average royalties of approximately 10%. This non-operated property has generated negative cash flow in the past two years and was expected to have negative cash flow in 2014 if not sold. This transaction is accretive on a cash flow basis to the Company as it reduces annualized operating expenses by $1.3 million and reduces decommissioning obligations by $3.0 million. These lands have no further development potential.
In the first quarter of 2014, the Company also committed to three property acquisitions and two minor property dispositions for a net cost of $0.8 million, which resulted in 6.0 gross (4.5 net) drilling locations. The Company considers the newly acquired lands to be very prospective for Cardium and Mannville drilling.
2014 CAPITAL PROGRAM
The Company commenced a 14 month, $33 million capital program in November 2013, of which 90% is directed toward the drilling, completion, equipping and tie-in of 11 net Cardium wells. Approximately $7.5 million of those funds were spent in 2013 to drill and complete one Cardium well, drill two additional Cardium wells, acquire surface leases and tangible equipment, and commence construction on the remainder of the winter program.
In November 2013, the Company estimated 2014 production to average 2,600 BOED. This estimate was made assuming the Company would only drill in the winter months of the year. The Company will be reviewing its capital program and guidance when it releases its financial and operating results for the first quarter of 2014. The Company will be reviewing whether greater production efficiency can be achieved by increasing the capital program to drill eight to nine months per year.
On March 24, 2014, Anderson received notice from TransCanada Pipelines Ltd. ("TransCanada") that as a result of an Order by the National Energy Board to reduce maximum operating pressure on the Nova Gas Transmission Ltd. system, transportation service at certain meter stations where the Company delivers natural gas will be fully restricted. The Company currently delivers approximately 1 MMcfd to these meter stations and has been advised that it will be required to shut in this production starting on or about April 24, 2014. TransCanada has not announced an estimate of the duration of the interruption. The Company is currently in the process of assessing the direct and indirect implications of the Order on its operations.
COMMODITY PRICES
The 2013 WTI oil price averaged $97.95 US per bbl ($100.95 Canadian per bbl). Differentials from Cushing, Oklahoma to Edmonton averaged $7.57 US per bbl. Anderson's average wellhead price was $89.89 Canadian per bbl. This compares to a 2012 WTI average oil price of $94.20 US per bbl ($94.10 Canadian per bbl), a differential of $7.87 US per bbl and an average Anderson wellhead price of $83.21 Canadian per bbl. Average wellhead prices are before hedging. The difference between Anderson's wellhead price and WTI Canadian is due to the price differential between Cushing, Oklahoma and Edmonton, oil transportation costs from the field to Edmonton and adjustments for oil quality.
The average 2013 NYMEX gas price was $3.73 US per MMBtu compared to $2.82 US per MMBtu in 2012. The 2013 AECO gas price averaged $3.01 per GJ ($3.17 per MMbtu) in 2013 compared to $2.26 per GJ ($2.38 per MMbtu) in 2012. Anderson's average plant gate price in 2013 was $2.93 per Mcf compared to $2.21 per Mcf in 2012. The difference between the AECO price and Anderson's plant gate price is due to transportation costs and the heat content of the gas.
The 2014 monthly WTI Canadian oil prices were $103.80 in January and $111.30 per bbl in February. Differentials from Cushing, Oklahoma to Edmonton were $13.07 US per bbl in January and $5.07 US per bbl in February. March prices to date have averaged approximately $111.60 WTI Canadian per bbl. AECO natural gas prices were $4.06 per GJ ($4.28 per MMBtu) in January and $7.19 per GJ ($7.58 per MMBtu) in February. March prices to date have averaged approximately $5.08 per GJ ($5.36 per MMBtu). Anderson's average plant gate price would be approximately $0.24 per MMBtu less than AECO excluding hedging.
Going forward, Anderson estimates that light oil prices will stay strong but will be volatile and will be influenced by geopolitical events. Cushing, Oklahoma to Edmonton differentials will continue to be volatile, as well as movements in the US dollar exchange rate.
In the first quarter of 2014, North American winter weather has contributed to much stronger natural gas pricing than we have seen in recent years. The winter weather has also reduced North American natural gas storage to levels we have not seen for many years. This should contribute to stronger natural gas pricing this summer compared to recent prior years. However, the forward strip pricing for natural gas remains disappointing. The Company currently has no plans to commence drilling operations for shallow natural gas as the current futures prices are inadequate to generate a competitive economic return. The Company has not drilled a shallow gas well since January 2010. The economics for horizontal light oil drilling are superior to any natural gas drilling available on Company's lands. With stronger natural gas pricing this winter, the Company has returned all of its operated shut-in gas to production. However, this production could be shut-in again if natural gas prices decline.
Natural gas prices are influenced by weather events and are tempered by the increasing supply of new shale gas. Until meaningful exports of natural gas commence from North America through liquefied natural gas projects, the Company believes that natural gas prices will be range-bound by weather events.
COMMODITY HEDGING CONTRACTS
Natural Gas
The Company has entered into fixed price physical contracts to sell 2,500 GJs per day for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72 per GJ. The Company has entered into fixed price derivative contracts to sell 2,500 GJs per day for January 1, 2014 to December 31, 2014 at an average AECO price of $3.55 per GJ.
Crude Oil
The Company has not hedged any crude oil volumes at this time.
The Company enters into hedging contracts to protect its capital program and continues to evaluate the merits of additional commodity hedging as part of a price management strategy.
RESERVES
GLJ Petroleum Consultants ("GLJ"), an independent evaluator, has completed a reserves report (the "GLJ Report") of all the Company's oil and natural gas properties effective December 31, 2013, prepared in accordance with procedures and standards contained in National Instrument 51-101 of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). The reserves definitions used in preparing the report are those contained in the COGE Handbook and NI 51-101. As of December 31, 2013, the Company had 3,447 MBOE PDP reserves (29% oil & NGL), 5,311 MBOE TP reserves (36% oil & NGL) and 8,822 MBOE P&P reserves (42% oil & NGL). The GLJ price forecast used in the evaluation is shown in Management's Discussion and Analysis for the year ended December 31, 2013.
The reserves report reflects the disposition of approximately $80 million in properties in 2013. The Cardium formation represents approximately 39%, 49% and 60% respectively of PDP, TP and P&P total BOE reserves volumes and 74%, 77% and 80% respectively of the total Company PDP, TP and P&P NPV 10 value. The Edmonton Sands shallow gas project represents approximately 9% of the total Company P&P NPV 10 value.
Of the seven wells drilled in the 2013 / 2014 winter drilling program, GLJ recognized one well as proved developed producing, two wells as proved developed non-producing, one well as proved undeveloped and one well as probable undeveloped. The two remaining wells were not recognized by GLJ in the year end reserves report.
The shut-in gas volumes that were returned to production in the first quarter are recognized by GLJ as proved developed non-producing in the year end reserves report.
SUMMARY OF OIL AND GAS RESERVES
| | December 31, 2013 | | December 31, 2012 | |
| Gross Working Interest Oil and Gas Reserves | Oil (Mbbls | ) | NGL
(Mbbls | ) | Gas (MMcf | ) | Total (MBOE | ) | Pre-tax
NPV 10
($M | ) | Oil (Mbbls | ) | NGL
(Mbbls | ) | Gas (MMcf | ) | Total (MBOE | ) | Pre-tax
NPV 10
($M | ) |
| Proved developed producing | 792 | | 216 | | 14,639 | | 3,447 | | 43,153 | | 2,089 | | 595 | | 25,150 | | 6,875 | | 114,369 | |
| Proved developed non-producing | 128 | | 25 | | 3,683 | | 767 | | 7,527 | | 69 | | 45 | | 4,635 | | 887 | | 7,438 | |
| Total proved | 1,608 | | 313 | | 20,336 | | 5,311 | | 61,608 | | 3,480 | | 964 | | 35,118 | | 10,297 | | 143,960 | |
| Proved plus probable | 3,150 | | 565 | | 30,642 | | 8,822 | | 100,312 | | 6,709 | | 1,814 | | 55,475 | | 17,770 | | 224,826 | |
| |
| CONTINUITY OF GROSS WORKING INTEREST RESERVES |
| |
| | Total Proved Developed Producing
(MBOE | ) | Total Proved (MBOE | ) | Total Proved
Plus Probable (MBOE | ) |
| Opening Balance, December 31, 2012 | 6,875 | | 10,297 | | 17,770 | |
| Extensions and improved recovery | 173 | | 412 | | 332 | |
| Technical revisions | 140 | | 261 | | (84 | ) |
| Acquisitions | 24 | | 114 | | 164 | |
| Dispositions | (2,488 | ) | (4,496 | ) | (8,083 | ) |
| Production | (1,277 | ) | (1,277 | ) | (1,277 | ) |
| Closing Balance, December 31, 2013 | 3,447 | | 5,311 | | 8,822 | |
The Company will provide more detailed information from its current reserves report in its Annual Information Form for the year ended December 31, 2013.
UNDEVELOPED LAND
Anderson has 226,343 gross (132,355 net) developed acres and 65,048 gross (27,988 net) undeveloped acres of land at December 31, 2013. Undeveloped land has been valued at $3.4 million by management.
OWNERSHIP
The management team of Anderson has been together for the last 12 years in the Company's private and public phases. They currently own 5.9 million shares, adding 0.9 million shares in 2013. Including current Board members, insiders own 18.2 million shares. Both management and the Board are long term shareholders. We have a vested interest in making this Company work and although we have had difficult times in the past couple of years, we believe that we can work things out and resurrect the stock price. We admit that it will take time, but we have a business plan in the Cardium light oil resource play that we believe will accomplish our goals and objectives.
I appreciate the support of the Board of Directors, the Company employees and our patient shareholders through a difficult year. We have repositioned ourselves to be more operationally active in 2014 which should benefit all of our shareholders.
SUMMARY
In summary, our winter program achieved the planned operational results. The Company continues to add to its Cardium drilling inventory and continues to make progress in rationalizing its legacy shallow gas asset base. More production data on the winter program will be available by the time we present our financial and operating results for the first quarter of 2014. A more fulsome discussion on remaining capital spending for 2014 will also be available at that time.
Brian H. Dau
President & Chief Executive Officer
March 31, 2014
Management's Discussion and Analysis