CALGARY, ALBERTA — (Marketwire) — 03/18/13 — Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX: AXL) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2012.
The Company estimates its first quarter 2013 production will be 3,900 to 4,200 BOED, of which approximately 55% is from high netback Cardium properties. Oil and NGL production is estimated to be approximately 43% of total BOED production in the quarter.
Total Company operating netbacks averaged $26.50 per BOE in the fourth quarter of 2012. Cardium operating netbacks averaged $44.32 per BOE in the fourth quarter. Operating netbacks per BOE in the first quarter of 2013 are estimated to be similar to the fourth quarter of 2012. Full cycle three year average FD&A costs including future development capital in the Cardium play were $36.77 per BOE on a TP basis and $25.81 on a P&P basis. Using three year production weighted average Cardium operating netbacks, this yields a recycle ratio of 2.03 on a P&P basis.
The Company–s first slick water frac completion was in February 2012. Since then, six new wells were frac–d with this technique, yielding substantially better initial production rates and economics. The Company continues to be an industry pacesetter for low costs with Cardium horizontal drilling and completion costs in this past winter–s program averaging $2.3 million per well. The wells drilled in the past winter are connected via short tie-ins to the Company–s pre-built infrastructure which reduced equipping and tie-in costs. The Company was able to drill wells in 10 to 15 days depending on the depth drilled, slick water fracture stimulate the wells approximately seven days later and have new oil production the following day, for an impressive cycle time average of 20 days.
The Company has seen five consecutive years of long term gas price declines by its independent reserves engineers. The Company no longer has any undeveloped shallow gas reserves contained in the reserves evaluation as of December 31, 2012. The Company–s shallow gas land, drilling locations and infrastructure awaits better natural gas pricing before drilling and well tie-in operations can resume. Today, 75% of the Company–s P&P reserves are located in the Cardium properties, and these Cardium properties comprise 90% of the pre-tax NPV 10 value of the Company.
Anderson has not drilled a gas well since mid-2010, and has been entirely focused on converting its historical shallow gas asset base into a Cardium light oil horizontal development company. This transition to light oil is necessary. The average NYMEX natural gas price in 2012 was $2.83 US per MMBtu. This resulted in an average natural gas price received by the Company of $2.21 per mcf in 2012, and the lowest natural gas price seen in the Company–s 11 year history. To put this price in perspective, the Company–s average natural gas price from 2009 to 2011 was $3.84 per mcf, and from 2006 to 2008 was $7.04 per mcf. In contrast, light oil prices remain very good, and unlike the heavy oil “bitumen bubble” which has caused heavy oil price differentials to widen out, the light oil price differential (i.e. the difference between the Edmonton par reference price and the WTI Cushing price) was $7.87 US per bbl in 2012, and is estimated to be $6.08 US per bbl in March 2013. All of the Company–s oil production is light oil. Anderson realized a field oil price (excluding hedging) of $83.21 per bbl in 2012 and estimates it will be slightly higher in the first quarter of 2013. Today, Anderson has the advantage of being totally focused on light oil development drilling in the Cardium formation with 165 gross (90 net) sections of Cardium prospective land. Our Cardium net drilling inventory increased by 35% in the past 12 months to 232 gross (148 net) drilling locations, and 74% of the net drilling inventory can be connected to our owned and operated facilities.
In 2012, the Garrington Cardium area net operating income (revenue minus royalties minus operating expenses) was $54.27 per BOE, with average operating expenses net of processing income of $4.85 per BOE. The Garrington Cardium property is the Company–s largest Cardium property and represents approximately 47% of the Company–s total pre-tax NPV 10 valuation. In 2012, its average production was 958 BOED and TP and P&P reserves were 3,771 and 6,120 MBOE respectively. This property contains a strategic 100% owned and operated oil battery and truck terminal which connects to the light oil Plains Rangeland pipeline system. The Company has been steadily increasing third party truck volumes from 50 m3 per day in early 2012 to over 250 m3 per day at the present time. The Company is investigating options to reconfigure this facility to substantially increase and attract third party truck volumes.
In addition to the substantive Cardium light oil drilling inventory, the Company has identified an important new play on its lands – the Second White Specks. The Company has 104 gross (46 net) sections of Second White Specks (“2WS”) land and has assembled a drilling inventory of 102 gross (59 net) drilling locations. This zone is 100 meters deeper than the Cardium formation and is the oil-source zone for the Cardium play and is oil-charged with similar quality light oil that is in the Cardium formation. To date, other operators have drilled six horizontal oil 2WS wells offsetting the Company lands. The Company believes this play can be exploited by drilling off existing Cardium drilling pads and handling the Second White Specks oil and solution gas at the Company–s operated Cardium facilities.
The Company no longer considers itself to be a shallow gas production and development company. The Company is a light oil horizontal development company focused almost exclusively on the Cardium with a stacked resource play in the Second White Specks. The Company–s assets are almost entirely west of the fifth meridian, and a two hour drive north of Calgary on predominantly year-round access land. With a new reserves report, excellent drilling results yielding high initial productivity, relatively low capital costs and an expanded drilling inventory, the Company continues to explore its options through a strategic alternatives process. Anderson has prepared a confidential data room to assist in this process. Qualified parties have signed confidentiality agreements to review information in this data room.
With recent property dispositions and existing bank lines, the Company was able to complete all of its recently restructured drilling commitments. This winters drilling program has demonstrated significant initial production results for slick water frac stimulations that were vastly superior to previously announced techniques. The Company continues to add to its Cardium drilling inventory.
STRATEGIC ALTERNATIVES
The Company is continuing its process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value. The strategic alternatives may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, or a drilling joint venture, either in one transaction, or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The Board of Directors believes that the Company–s shares trade at a discount to the value of the underlying assets, especially given its high quality light oil production base, prospective horizontal light oil drilling inventory and significant tax pools. The Board of Directors has established a special committee comprised of independent directors of the Company to oversee the process and has retained BMO Capital Markets and RBC Capital Markets as its financial advisors to assist the Special Committee and the Board of Directors with the process.
It is Anderson–s current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction or the impact it will have on the Company–s financial position. The Company has not set a definitive schedule to complete the evaluation.
(i) Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts. 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.
WINTER DRILLING PROGRAM
Anderson has completed its winter drilling program with 6 gross (4.3 net revenue) Cardium oil wells drilled, completed and on production. The Company has completed all of its drilling commitments on third party lands. Wells were drilled in the Ferrier, Willesden Green, Garrington and Buck Lake project areas. Drilling and completion costs were approximately $2.3 million per well in this program.
SLICKWATER FRAC TECHNOLOGY
In February 2012, Anderson initiated its first slick water frac completion in the Cardium. The Company had previously employed gelled water and gelled hydrocarbon frac techniques. Encouraged by the success of its first slick water frac completion and recent industry activity in slick water frac technology, the Company used slick water fracs on its six well Cardium horizontal drilling program this winter. Production information from the seven wells confirms that initial production is significantly higher when slick water frac technology is used in the Cardium formation compared to previously used gelled water and gelled hydrocarbon frac techniques. This conclusion is supported by industry activity offsetting Company interest lands. For the wells drilled by the Company that were completed using slick water frac technology, the average initial production (“IP”) performance for various calendar day averages is shown below:
(i) 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.
Short term production rates can be influenced by flush production effects from fracture stimulations in horizontal wellbores and may not be indicative of longer term production performance. Individual well performance can vary.
DRILLING INVENTORY
The Company–s drilled and drill-ready light oil horizontal drilling inventory is outlined below:
(i) Net is net revenue interest
The Company–s remaining Edmonton Sands shallow gas drilling inventory is now estimated to be 542 gross (307 net) locations.
The recently completed reserves report effective December 31, 2012, and summarized herein, includes proved plus probable reserves for 48 net Cardium horizontal oil, 0.75 net other horizontal oil and no Edmonton Sands locations. There are a further 100 net Cardium horizontal and 61 net other horizontal light oil locations that are not included in the reserves report.
PRODUCTION
The property dispositions announced in the fourth quarter of 2012 have all been completed. Net of all of the properties sold, the Company estimates first quarter 2013 production to be approximately 3,900 to 4,200 BOED of which 55% is from high netback Cardium properties. Oil & NGL production is estimated to be 43% of the total BOED production in the quarter. Given the low price environment, the Company shut-in 700 Mcfd of natural gas production in the first quarter of 2012, and shut-in an additional 900 Mcfd in the first quarter of 2013.
2013 CAPITAL PROGRAM
For the first half of 2013, Anderson estimates its capital program to approximate cash flows, dedicated exclusively to its Cardium horizontal drilling program. After spring break up, the Company will revisit its 2013 capital program.
COMMODITY HEDGING CONTRACTS
Crude Oil. As part of its price management strategy, the Company has added to its fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. As of March 15, 2013, the average volumes and prices for these derivative contracts are summarized below:
The Company entered 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. The Company has not hedged any natural gas volumes at this time.
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, 2012, 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 (“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, 2012, the Company had 6.9 MMBOE PDP reserves (39% oil & NGL), 10.3 MMBOE TP reserves (43% oil & NGL) and 17.8 MMBOE P&P reserves (48% oil & NGL). The GLJ price forecast used in the evaluation is shown in Management–s Discussion and Analysis for the year ended December 31, 2012.
The reserves report reflects the disposition of $74 million in properties in 2012, the previously announced termination of the Company–s shallow gas drilling commitment and the negative impact of significant reductions in natural gas price forecasts over the past year. The percentage of PDP, TP and P&P total BOE reserves volumes from the Cardium formation represent approximately 59%, 66% and 75% of total Company reserves volumes respectively. By product, approximately 96% of P&P oil and NGL reserves and 55% of P&P natural gas reserves (primarily solution gas) are in the Cardium formation. The Cardium P&P NPV 10 value is approximately 90% of the total Company P&P NPV 10 value. The Edmonton Sands shallow gas project represents approximately 5% of the total Company P&P NPV 10 value.
SUMMARY OF OIL AND GAS RESERVES
Finding, development and acquisition (“FD&A”) costs on a total company basis were indeterminate in 2012, as the Company–s proceeds from selling assets exceeded its field capital program expenditures. The Company believes that finding and development costs should include acquisition and disposition costs as these functions are not segregated operationally in the Company, and it is a useful and commonly used reference for shareholders and analysts. In the Cardium play, full-cycle, three year average FD&A costs including future development capital were $36.77 per BOE on a TP basis and $25.81 per BOE on a P&P basis. This compares to 2012 one year FD&A costs of $1.15 per BOE on a TP basis and $3.12 per BOE on a P&P basis and 2011 one year FD&A costs of $39.16 per BOE on a TP basis and $26.68 per BOE on a P&P basis. Using three-year production weighted average Cardium operating netbacks, this yields a recycle ratio of 2.03 before hedging gains, on a P&P basis. The aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total FD&A costs related to reserve additions for that year.
The Company–s reserve life indices are 7.0 years TP and 12.0 years P&P based on an annualized mid-point estimate of the first quarter production for 2013.
Anderson–s P&P pre-tax NPV 10 at December 31, 2012 was $224.8 million, 37% lower than at December 31, 2011 as a result of the property sales in the year and lower price forecasts used by GLJ. At December 31, 2012, GLJ–s natural gas price and Edmonton crude oil price forecasts for the years 2013 to 2021 were an average of $0.91 per MMBtu and $7.63 per bbl lower respectively than they were last year.
In 2012, the Company experienced negative technical revisions of 0.5 MMBOE TP and 1.0 MMBOE P&P as well as negative economic factor revisions of 1.8 MMBOE TP and 4.1 MMBOE P&P. These negative economic factors were related to the reduction of undeveloped natural gas reserves in the Edmonton Sands formation.
The Company disposed of 7.1 MMBOE TP and 11.4 P&P reserves. Approximately 75% of the TP and 81% of the P&P dispositions were due to the $74 million in property sales during 2012. Dispositions also include 1.8 MMBOE TP and 2.2 MMBOE P&P reserves associated with the cancellation of the Edmonton Sands drilling commitment. The Company was able to cancel its previous Edmonton Sands farm-in commitment in exchange for a carried interest in one net Cardium horizontal well from this winter–s drilling program. The cancellation of the Edmonton Sands commitment combined with the economic factor revision for this area, plus minor changes to the Cardium future development capital, caused a significant reduction in future development capital compared to the previous year–s reserve report. Future development capital on TP reserves is $66.8 million as compared to $149.8 million on last year–s report, and is $145.3 million for P&P reserves, as compared to $264.9 million last year.
The Company will provide more detailed information regarding its December 31, 2012 reserves report as part of its annual information form filing in March 2013.
FINANCIAL RESULTS
Capital expenditures were $10.1 million in the fourth quarter of 2012 with $8.3 million spent on drilling and completions and $1.3 million spent on facilities. This compares to capital expenditures of $41.0 million in the fourth quarter of 2011. Proceeds from the sale of assets were $37.0 million in the fourth quarter of 2012.
Anderson–s funds from operations were $5.7 million in the fourth quarter of 2012 compared to $17.0 million in the fourth quarter of 2011. The Company–s average crude oil and natural gas liquids sales prices in the fourth quarter of 2012 were $79.73 and $52.02 per barrel compared to $96.33 and $72.71 respectively per barrel in the fourth quarter of 2011. The Company–s average natural gas sales price was $3.16 per Mcf in the fourth quarter of 2012 compared to $3.20 per Mcf in fourth quarter of 2011. The Company recorded a loss of $8.9 million in the fourth quarter of 2012 compared to a loss of $32.2 million in the fourth quarter of 2011. The Company–s operating netback was $26.50 per BOE in the fourth quarter of 2012 compared to $29.88 per BOE in the fourth quarter of 2011. The decrease in the operating netback was primarily due to the decrease in oil and NGL prices and oil volumes. Anderson–s operating netback for its Cardium horizontal properties in the year ended December 31, 2012 was $44.73 per BOE compared to $6.07 per BOE for the remainder of its properties (exclusive of hedging). Anderson–s operating netback for its Cardium properties was $44.32 per BOE in the fourth quarter of 2012.
STRATEGY
Subject to the outcome of the strategic alternatives process, the Company intends to continue to focus on converting its asset base so that more than 50% of its production is from oil and NGL.
Brian H. Dau
President & Chief Executive Officer
March 18, 2013
Management–s Discussion and Analysis
FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011
The following management–s discussion and analysis is dated March 15, 2013 and should be read in conjunction with the audited consolidated financial statements of Anderson Energy Ltd. (“Anderson” or the “Company”) for the years ended December 31, 2012 and 2011. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).
Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition (“FD&A”) costs, operating netback and barrels of oil equivalent (“BOE”). Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See “Review of Financial Results – Funds from Operations” for details of this calculation. Funds from operations represent both an indicator of the Company–s performance and a funding source for on-going operations. FD&A costs measure the cost of reserves additions and are an indicator of the efficiency of capital expended in the period. Operating netback is calculated as oil and gas sales plus realized gains/losses on derivative contracts less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, financing, depletion and depreciation expenses, and gains or losses on sale of property, plant and equipment. Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. Although the intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants, BOEs 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. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1 and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value. These terms are not defined by International Financial Reporting Standards (“IFRS”) and therefore are referred to as additional GAAP measures.
All references to dollar values are to Canadian dollars unless otherwise stated. Production volumes are measured upon sale unless otherwise noted. Definitions of the abbreviations used in this discussion and analysis are located on the last page of this document.
REVIEW OF FINANCIAL RESULTS
Overview. Anderson focused on improving its overall financial position during 2012. Proceeds from the disposition of properties have been used to pay down bank loans and fund a modest level of capital spending. However, the dispositions have contributed to lower production volumes and related cash flows from operations. The natural declines of oil and gas production, shut-ins of uneconomic gas production, lower capital spending during 2012 and comparatively lower commodity prices have also impacted operating and financial results for the year ended December 31, 2012 compared to 2011.
Bank loans plus cash working capital deficiency (excludes unrealized gain or loss on derivative contracts) decreased to $64.5 million at December 31, 2012 from $132.7 million at December 31, 2011. Funds from operations of $29.6 million for 2012 were 46% lower than 2011 as a result of the substantial drop in natural gas prices (39% decrease), declines in NGL prices (18% decrease), oil prices (11% decrease) and overall lower production volumes (21% decrease). Funds from operations for the fourth quarter of 2012 were $5.7 million, consistent with the third quarter of 2012, but were $11.3 million lower than the fourth quarter of 2011 primarily due to reduced production volumes (43% decrease).
The Company drilled 7 gross (6.5 net capital) new wells during the 2012 financial year; 3 gross (2.5 net capital) wells early in the year and 4 gross (4 net capital) wells in the fourth quarter. Of the wells drilled in the fourth quarter, 2 gross (1.3 net revenue) wells were brought on late in the fourth quarter and the remaining 2 gross (1.5 net revenue) wells were brought on early in 2013. An additional 2 gross (1.75 net capital, 1.5 net revenue) wells were drilled and brought on production early in 2013.
Revenue and production for the fourth quarter and year ended December 31, 2012 declined substantially when compared to the same periods ended December 31, 2011 for three main reasons:
During the year ended December 31, 2012, Anderson sold interests in 17 properties for total consideration of $73.9 million (2011 – $11.6 million). Total production sold was approximately 2,292 BOED (71% natural gas) and includes 54 BOED of dry gas swapped in exchange for additional interests in Cardium drillable lands at Garrington.
The Company suspended its shallow gas drilling program prior to 2011 because of low natural gas prices, and curtailed its oil drilling program during 2012 due to the strategic review process and limited funds. Accordingly, natural production declines were not replaced, resulting in decreases in gas sales throughout 2011 and 2012, and declines in oil production in 2012. In addition, early in the year the Company shut-in over 700 Mcfd of natural gas production that was uneconomical to produce in the current price environment, thus contributing to lower natural gas sales during 2012.
Approximately 1,534 BOED of total production was sold in the fourth quarter of 2012, contributing to the decline in production from 5,770 BOED in the third quarter to 4,500 BOED in the fourth quarter of 2012. As the properties were sold part way through the quarter, there was still 645 BOED of production from these properties reported in the fourth quarter of 2012.
The Company estimates first quarter 2013 production to be approximately 3,900 to 4,200 BOED of which 43% is estimated to be from oil and natural gas liquids production.
Prices. For the 2012 financial year, natural gas prices fell to near historic lows, and the Company benefitted from the change in focus to oil beginning in 2010 as oil and natural gas liquids production volumes represented 35% of total BOED production (2011 – 31%), partially mitigating the impact of low natural gas prices. In the fourth quarter of 2012, oil and natural gas liquids production volumes represented 33% of total BOED production (fourth quarter of 2011 – 36%).
World and North American benchmark prices for oil remain volatile and as described below, the Company has entered into certain derivative contracts to partially hedge oil prices. Differentials between WTI oil prices and prices received in Alberta are affected by factors including refining demand and pipeline capacity. Light, sweet oil differentials between Cushing, Oklahoma and Edmonton, Alberta were adversely affected by transportation and market factors beginning late in 2011 and continuing into 2012. These differentials averaged $10.53 US per bbl discount in the first quarter of 2012, and improved to $10.25, $7.21 and $3.49 US per bbl in the second, third and fourth quarter of 2012 respectively. The average differential for the year ended December 31, 2012 was a $7.87 US per bbl discount, compared to an average $1.46 US per bbl premium as recently as the fourth quarter of 2011. Going into 2013, light, sweet oil differentials are expected to be comparable to the annual average rate during 2012 and may remain volatile in the future depending on supply, transportation alternatives and refining demand.
Natural gas prices were low throughout 2011. Market conditions, including high supply and low demand due to a warm winter in North America, resulted in the reduction in natural gas prices during the first six months of 2012. However, the increased demand for natural gas for electrical power generation during the hot summer throughout North America contributed to modest price gains in the last half of the year.
The above noted oil price in 2012 does not include a realized gain on derivative contracts of $5.4 million (December 31, 2011 – $0.6 million loss). The realized oil price including this gain was $101.08 per barrel for the fourth quarter of 2012 and $93.06 per barrel for the year, compared to $94.94 per barrel for the fourth quarter of 2011 and $92.06 for the year ended December 31, 2011.
The Company–s average natural gas sales price was $3.16 per Mcf for the three months ended December 31, 2012, 41% higher than the third quarter of 2012 price of $2.24 per Mcf and 1% lower than the fourth quarter of 2011 price of $3.20 per Mcf. For the year ended December 31, 2012, the Company–s average natural gas sales price was $2.21 per Mcf compared to $3.60 per Mcf for 2011. The natural gas price for the year ended 2012 includes a gain of $0.1 million on the Company–s fixed price natural gas contracts, compared to a gain of $1.2 million for 2011.
Commodity contracts. At December 31, 2012, the following derivative contracts were outstanding and recorded at estimated fair value:
By comparison, WTI Canadian averaged $103.04 per bbl in the first quarter of 2012, $94.29 per bbl in the second quarter of 2012, $91.70 per bbl in the third quarter and $87.39 per bbl in the fourth quarter of 2012.
Derivative contracts had the following impact on the consolidated statements of operations:
In October 2012, 500 bpd of derivative contracts for the months of November and December 2012 were settled for a gain of $0.4 million which was reflected in the financial results for the fourth quarter of 2012.
Fixed price contracts. The Company entered into physical contracts to sell 7,000 GJs per day of natural gas for August and September 2012 at an average AECO price of $2.45 per GJ. The Company realized a gain on fixed price natural gas contracts of $0.1 million for the year ended December 31, 2012 as compared to a gain of $1.2 million for the year ended December 31, 2011.
Royalties. For the year ended December 31, 2012, the average rate for royalties was 10.3% of revenue (December 31, 2011 – 11.8%). For the fourth quarter of 2012, the average rate for royalties was 9.7% of revenue compared to 10.2% of revenue in the third quarter of 2012 and 12.8% of revenue in the fourth quarter of 2011. The decrease in the average royalty rate for the year and quarter ended December 31, 2012 is due to reduced royalty rates at lower commodity prices. Oil wells drilled on Crown lands during 2011 and 2012 qualified for royalty incentives that reduce average Crown royalties for periods of up to 30 months from initial production, after which Crown royalties are expected to increase from current levels.
Royalties as a percentage of total oil and gas sales are highly sensitive to prices and adjustments to gas cost allowance and so royalty rates can fluctuate from quarter to quarter and year to year.
Operating expenses. Operating expenses were $12.11 per BOE for the three months ended December 31, 2012 compared to $11.28 per BOE in the third quarter of 2012 and $8.30 per BOE in the fourth quarter of 2011. The lower operating expense for the fourth quarter of 2011 was primarily due to a reduction in estimated accrued liabilities related to certain gas plant processing fees from earlier periods. Operating expenses were $10.90 per BOE for the year ended December 31, 2012 compared to $10.52 per BOE in 2011.
Transportation expenses. For the year ended December 31, 2012, transportation expenses were $0.22 per BOE (December 31, 2011 – $0.58 per BOE). For the fourth quarter of 2012, transportation expenses were $0.10 per BOE compared to $0.13 per BOE in the third quarter of 2012 and $0.44 per BOE in the fourth quarter of 2011. The decrease in transportation expenses in 2012 relative to 2011 is due to the direct tie-in of the Garrington battery to a newly constructed lateral pipeline in late October 2011, thereby replacing clean oil trucking charges with a pipeline tariff, which is netted from the Company–s oil sales price.
Depletion and depreciation. Depletion and depreciation was $44.4 million ($19.96 per BOE) for the year ended December 31, 2012 compared to $52.9 million ($18.85 per BOE) in 2011. Depletion and depreciation was $9.0 million ($21.70 per BOE) in the fourth quarter of 2012 compared to $10.1 million ($19.01 per BOE) in the third quarter of 2012 and $15.0 million ($20.49 per BOE) in the fourth quarter of 2011. The decrease in the amount of depletion and depreciation for the year and the fourth quarter of 2012 compared to the same periods of 2011 is due to lower overall production volumes. Proved plus probable reserves volumes are included in the determination of depletion expense. Natural gas reserves volumes were reduced due to low natural gas prices, property dispositions, and the termination of the Edmonton Sands farm-in agreement, thus resulting in higher depletion and depreciation expense per BOE.
Impairment loss. Oil and natural gas assets are grouped into cash generating units (“CGUs”) for impairment testing. The Company had previously grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. In 2012, a significant portion of the assets in the Deep Gas and Non-core CGUs were sold and the remaining assets were regrouped into the following CGUs: Gas, and Horizontal Cardium. The Horizontal Cardium CGU retained the same group of assets, but was renamed to better reflect the nature of those assets. The remaining assets in the Deep Gas and Non-core CGUs more closely resemble the operational, management and monitoring, product composition, and cash inflows of the assets within the Shallow Gas CGU. Accordingly, the remaining Deep Gas and Non-core assets have been grouped with the Shallow Gas assets to form the new Gas CGU.
In 2012, declines in forecasted commodity prices were indicators of impairment. Forecasted commodity prices at December 31, 2012 declined between 14% and 18% for natural gas and between 4% and 16% for light, sweet crude oil when compared to December 31, 2011. In the second quarter of 2012, the Company tested its gas-weighted CGUs for impairment and determined that the aggregate carrying value of these CGUs was $20 million higher than the recoverable amounts and impairments were recorded ($13 million for the Shallow Gas CGU and $7 million for the Deep Gas CGU). In the third and fourth quarters of 2012, the Company tested all of its CGUs for impairment and determined that no additional charges for impairment were required.
General and administrative expenses. General and administrative expenses excluding share-based compensation were $2.5 million ($6.07 per BOE) for the fourth quarter of 2012 compared to $2.1 million ($3.88 per BOE) in the third quarter of 2012 and $2.2 million ($3.03 per BOE) for the fourth quarter of 2011. For the year ended December 31, 2012, general and administrative expenses excluding share-based compensation were $9.2 million ($4.12 per BOE) compared to $9.4 million ($3.36 per BOE) for 2011. The decrease in cash general and administrative expenses is the result of lower employee compensation associated with reduced staff and decreased audit and tax fees as the comparative period in 2011 had higher fees associated with the adoption of IFRS. In the fourth quarter of 2012, the Company laid off some of its staff. One time severance costs of $0.5 million were recorded in the fourth quarter. Beginning in December 2012, office rent decreased by $0.1 million per month as a result of the corporate office move into lower cost office space.
Capitalized general and administrative costs are limited to compensation and benefits and associated office rent of staff involved in capital activities.
Share-based compensation. The Company accounts for share-based compensation plans using the fair value method of accounting. Share-based compensation expense was $1.0 million in 2012 ($0.8 million net of amounts capitalized) versus $1.5 million ($1.0 million net of amounts capitalized) in 2011. Share-based compensation costs were $0.1 million for the fourth quarter of 2012 ($0.2 million net of amounts capitalized) versus $0.3 million ($0.2 million net of amounts capitalized) in the fourth quarter of 2011.
Finance expenses. Finance expenses were $3.5 million for the fourth quarter of 2012, compared to $3.9 million in the third quarter of 2012 and $3.4 million in the fourth quarter of 2011. Finance expenses were $14.8 million for the year ended December 31, 2012, compared to $11.9 million in the comparable period of 2011. The increase in finance expenses from 2011 is the result of higher interest and accretion on the $96 million (principal) of convertible debentures issued on December 31, 2010 and June 8, 2011 at 7.5% and 7.25% respectively, partially offset by lower accretion on decommissioning obligations. The average effective interest rate on outstanding bank loans was 4.7% for the year ended December 31, 2012 compared to 5.3% for the comparable period in 2011.
Decommissioning obligations. In the fourth quarter of 2012, the Company disposed of $9.7 million in decommissioning obligations related to property dispositions, and increased decommissioning obligations by $0.3 million primarily relating to drilling activity in the quarter. Accretion expense was $0.2 million for the fourth quarter of 2012 compared to $0.2 million in the third quarter of 2012 and $0.3 million in the fourth quarter of 2011 and was included in finance expenses. The decommissioning liability at December 31, 2012 decreased by $16.4 million compared to December 31, 2011, primarily due to the disposition of $20.9 million of provisions related to the sale of assets during the year. Provisions incurred were $1.2 million, down from the $4.9 million incurred during 2011 due to lower capital expenditures in 2012. Changes in estimates added $2.7 million ($2011 – $6.4 million) to the provision, and accretion expense added $1.1 million (2011 – $1.6 million).
The risk-free discount rates used by the Company to measure the obligations at December 31, 2012 were between 1.0% and 2.5% (December 31, 2011 – 0.9% to 3.1%) depending on the timelines to reclamation and decreased from the start of the year as a result of changes in the Canadian bond market.
Income taxes. Anderson is not currently taxable and has the following estimated tax pool balances at December 31, 2012. Non-capital losses are estimated assuming certain discretionary claims related to tax pools are made in the current year. Tax pool classifications are estimates as some new wells have not yet had their status as exploratory or development confirmed.
Funds from operations. Funds from operations for the fourth quarter of 2012 were $5.7 million ($0.03 per share), substantially equivalent to the $5.7 million ($0.03 per share) recorded in the third quarter of 2012 and down 66% from the $17.0 million ($0.10 per share) recorded in the fourth quarter of 2011. Funds from operations for the year ended December 31, 2012 were $29.6 million ($0.17 per share), down 46% from the $54.5 million ($0.32 per share) recorded for 2011. Property dispositions contributed to lower funds from operations in 2012. The decrease in funds from operations compared to 2011 is also due to lower commodity prices for natural gas (39%), oil (11%) and NGLs (18%) in the year ended December 31, 2012 versus the year ended December 31, 2011. Production declines in natural gas, oil and NGLs of 24%, 14% and 13% respectively in the year ended December 31, 2012 compared to December 31, 2011 also contributed to lower funds from operations in 2012.
Earnings. The Company reported a loss of $8.9 million in the fourth quarter of 2012 compared to earnings of $0.1 million for the third quarter of 2012 and a loss of $32.2 million for the fourth quarter of 2011. In the fourth quarter of 2012, earnings were impacted by losses recognized on the Company–s asset dispositions. Overall, the dispositions during the 2012 financial year resulted in a net loss on sale of property, plant and equipment in the amount of $0.7 million (2011 – gain of $4.7 million).
The Company–s funds from operations and earnings are highly sensitive to changes in factors that are beyond its control. An estimate of the Company–s sensitivities to changes in commodity prices, exchange rates and interest rates is summarized below:
This sensitivity analysis was calculated by applying different pricing, interest rate and exchange rate assumptions to the 2012 actual results related to production, prices, royalty rates, operating costs and capital spending. As the contribution of oil production continues to increase as a percentage of total production, the impact of oil prices will be more significant and the impact of natural gas prices will be less significant to funds from operations and earnings than is shown in the table above.
CAPITAL EXPENDITURES
The Company spent $10.1 million on capital expenditures and proceeds on dispositions were $37.0 million in the fourth quarter of 2012. Capital expenditures were $34.9 million for the year ended December 31, 2012 and proceeds on disposition were $73.9 million. The breakdown of expenditures is shown below:
For the year ended December 31, 2012, the Company drilled 7 gross (6.5 net capital) Cardium horizontal wells. Of the total 7 gross wells drilled, the Company drilled 4 gross (4 net capital) Cardium horizontal wells in the fourth quarter of 2012. The Company completed its winter drilling program with an additional 2 gross (1.75 net capital, 1.5 net revenue) wells drilled during the first quarter of 2013.
RESERVES
The Company–s reserves were evaluated by GLJ Petroleum Consultants (“GLJ”) in accordance with National Instrument 51-101 (“NI 51-101”) as of December 31, 2012, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook. The reserves definitions used in preparing the report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The tables in this section are excerpts from what will be contained in the Company–s Annual Information Form for the year ended December 31, 2012 (“AIF”) as the Company–s NI 51-101 annual required filings.
At December 31, 2012, the Company–s proved developed producing (“PDP”), total proved (“TP”) and proved plus probable (“P&P”) reserves were 6.9 MMBOE, 10.3 MMBOE and 17.8 MMBOE respectively.
Oil and NGL reserves now represent 39% of the Company–s PDP, 43% of TP and 48% of the P&P reserves as compared to 33%, 29% and 31% respectively at December 31, 2011.
GROSS WORKING INTEREST OIL AND GAS RESERVES(1)
As at December 31, 2012
NET PRESENT VALUE BEFORE INCOME TAXES(1)(2)
As at December 31, 2012
GLJ December 31, 2012 Price Forecast, Escalated Prices
The estimated net present value of future net revenues presented in the table above does not necessarily represent the fair market value of the Company–s reserves.
Total future development costs included in the reserves evaluation were $66.8 million for total proved reserves and $145.3 million for proved plus probable reserves. Further details related to future development costs, including assumptions regarding the timing of the expenditures, will be included in the Company–s AIF for the 2012 fiscal year. Future development costs are associated with the reserves as disclosed in the GLJ report and do not necessarily represent the Company–s current exploration and development budget.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at December 31, 2012
GLJ Forecast Prices and Costs
The Company–s reserves life indices are 7.0 years total proved and 12.0 years proved plus probable, based on the midpoint of the estimated first quarter 2013 production. With an average $0.91 per MMBtu reduction in GLJ–s natural gas price outlook and $7.63 per bbl decrease in Edmonton crude oil in the years 2013 to 2021, the Company experienced a negative revision for economic factors of 1.8 MMBOE for total proved and 4.1 MMBOE for proved plus probable reserves. The economic factors negative revision was almost entirely related to the Company–s undeveloped gas reserves in the Edmonton Sands properties. In addition to the economic factors, the Company experienced negative technical revisions of 0.5 MMBOE total proved and 1.0 MMBOE proved plus probable reserves. Reserves additions before revisions were 1.0 MMBOE total proved and 2.1 MMBOE proved plus probable, predominantly from Cardium oil horizontal drilling.
FINDING, DEVELOPMENT AND ACQUISITION COSTS – CARDIUM PROPERTIES ONLY
Year Ended December 31, 2012
FD&A costs on a total company basis were indeterminate in 2012, as the Company–s proceeds from selling assets exceeded its field capital program expenditures. The Company believes that finding and development costs should include acquisition and disposition costs as these functions are not segregated operationally in the Company, and it is a useful and commonly used reference for shareholders and analysts. In the Cardium play, full cycle three year average FD&A costs including future development capital were $36.77 per BOE on a TP basis and $25.81 per BOE on a P&P basis. This compares to 2012 one year FD&A costs of $1.15 per BOE on a TP basis and $3.12 per BOE on a P&P basis and 2011 one year FD&A costs of $39.16 per BOE on a TP basis and $26.68 per BOE on a P&P basis. The aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total FD&A costs related to reserve additions for that year.
SHARE INFORMATION
The Company–s shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol “AXL”. As of March 15, 2013, there were 172.5 million common shares outstanding, 14.3 million stock options outstanding, $50.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.55 per common share and $46.0 million principal amount of convertible debentures which are convertible into common shares at a conversion price of $1.70 per common share. During 2012, no common shares (2011 – 64,400) were issued under the employee stock option plan.
SHARE PRICE ON TSX
The statistics above include trading on the Toronto Stock Exchange only. Shares also trade on alternative platforms like Alpha, Chi-X, Pure and Omega. Approximately 20 million common shares traded on these alternative exchanges in 2012 (2011 – 99.7 million). Including these exchanges, an average of 260,556 common shares traded per day in 2012 (2011 – 966,254), representing a turnover ratio of 38% (2011 – 140%).
RELATED PARTY TRANSACTIONS
On June 8, 2011, the Company issued 1,575 Series B Convertible Debentures to management and directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.6 million as part of a $46.0 million bought deal offering of convertible debentures.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2012, the Company had outstanding bank loans of $48.1 million, convertible debentures of $96.0 million (principal) and a cash working capital deficiency (excludes unrealized gain on derivative contracts) of $16.4 million. The working capital deficiency is largely due to accruals associated with the capital program in the last quarter of the year and will be funded through the available credit facilities and future operating cash flows. The following table shows the changes in bank loans plus cash working capital deficiency:
The continued development of the Company–s oil and gas assets are dependent on the ability of the Company to secure sufficient funds through operations, bank facilities and other sources from the strategic alternative process. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital.
The Company had commitments to drill five horizontal wells in the Cardium formation on or before March 1, 2013 and earned an average 70 per cent working interest in the wells. The commitments were met for four of the wells prior to December 31, 2012, and the remaining commitment was met in January 2013. The Company does not have any other outstanding drilling commitments as at December 31, 2012.
At December 31, 2012, the Company had total credit facilities of $65 million, consisting of a $55 million revolving term credit facility and a $10 million working capital credit facility with a syndicate of Canadian banks. Advances can be drawn in either Canadian or U.S. funds and bear interest at the bank–s prime lending rate, bankers– acceptance or LIBOR loan rates plus applicable margins. These margins vary from 3% to 4% depending on the borrowing option used. At December 31, 2012, no amounts were drawn in U.S. funds. The Company had $16.5 million of credit available at December 31, 2012. Anderson will prudently use its bank loan facilities to finance its operations as required.
For the first half of 2013, Anderson estimates its capital program to approximate cash flows, dedicated exclusively to its Cardium horizontal drilling program. After spring break up, the Company will revisit its 2013 capital program.
The available lending limits under the bank facilities are reviewed twice a year and are based on the bank syndicate–s interpretation of the Company–s reserves and future commodity prices. The last review was conducted on December 15, 2012. The revolving term credit facility and the working capital credit facility have a maturity date of July 10, 2013, and all outstanding advances become repayable on July 10, 2013. There can be no assurance that the amount of the available bank lines will not be adjusted at the next scheduled review to be completed prior to May 15, 2013.
OFF BALANCE SHEET ARRANGEMENTS
The Company had no guarantees or off-balance sheet arrangements other than as described below under “Contractual Obligations.”
CONTRACTUAL OBLIGATIONS
The Company enters into various contractual obligations in the course of conducting its operations. At December 31, 2012, these obligations include:
These obligations are described further in notes 19 and 21 to the consolidated financial statements for the years ended December 31, 2012 and 2011.
CRITICAL ACCOUNTING ESTIMATES
The Company–s significant accounting policies are disclosed in note 3 to the consolidated financial statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results than reported. The Company–s management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results that differ materially from current estimates.
Oil and gas reserves. Proved and probable reserves, as defined by the Canadian Securities Administrators in NI 51-101 with reference to the Canadian Oil and Gas Evaluation Handbook, are estimated using independent reserves evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 percent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50 percent statistical probability that it will be less. The equivalent statistical probabilities for the proved component of proved and probable reserves are 90 percent and 10 percent, respectively. Determination of reserves is a complex process involving judgments, estimates and decisions based on available geological, engineering, production and any other relevant data. These estimates are subject to material change as economic conditions change and ongoing production and development activities provide new information.
Purchase price allocations, depletion and depreciation and amounts used in impairment calculations are based on estimates of oil and gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and timing of future capital expenditures. By their nature, these estimates are subject to measurement uncertainties and interpretations and the impact on the financial statements could be material. The Company expects that over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels and may be affected by changes in commodity prices.
Recoverable amounts of CGUs. The recoverable amount of a CGU used in the assessment of impairment is the greater of its value-in-use (“VIU”) and its fair value less costs to sell (“FVLCTS”). VIU is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves. FVLCTS refers to the amount obtainable from the sale of a CGU in an arm–s length transaction between knowledgeable, willing parties, less costs of disposal. The criteria used in the estimation of this amount are discussed in note 5 to the consolidated financial statements.
At December 31, 2012 the recoverable amounts of the Company–s CGUs were based on their estimated FVLCTS. Note 5 outlines the factors considered in estimating these amounts. The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company–s oil and gas assets are made at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors may result in significant changes to the estimated recoverable amounts of CGUs.
Decommissioning obligations. The Company is required to set up a provision for future removal and site restoration costs. The Company must estimate these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to property, plant and equipment and the appropriate liability account over the expected service life of the asset. The estimate of future removal and site restoration costs involves a number of estimates related to timing of abandonment, determination of the economic life of the asset, costs associated with abandonment and site restoration, discount rates and review of potential abandonment methods.
Income taxes. The determination of the Company–s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ from that estimated and recorded by management. The Company estimates its future income tax rate in calculating its future income tax liability. Various assumptions are made in assessing when temporary differences will reverse and this will impact the rate used.
Allowance for doubtful accounts. The Company maintains an allowance for doubtful accounts to provide for receivables which may ultimately be uncollectible. The allowance is determined in light of a number of factors including company specific conditions, economic events and the Company–s historical loss experience. The allowance is assessed quarterly by a detailed formal review of accounts receivable balances.
Share-based compensation. In order to recognize share-based compensation costs, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, forfeitures, volatility of the underlying security and expected dividend yields. These assumptions may vary over time.
NEW AND PENDING ACCOUNTING STANDARDS
Standards that are issued and that the Company reasonably expects to be applicable at a future date are listed below.
IFRS 9 – Financial Instruments. IFRS 9, as issued, reflects the first phase of the IASB–s work on the replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS 39. The standard is effective for annual periods beginning on or after January 1, 2015. In subsequent phases, the IASB will address classification and measurement of financial liabilities, hedge accounting and derecognition.
IFRS 10 – Consolidated Financial Statements. IFRS 10 requires an entity to consolidate an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. IFRS 10 replaces SIC-12 Consolidation – Special Purpose Entities and parts of IAS 27 Consolidated and Separate Financial Statements. The standard is effective for annual periods beginning on or after January 1, 2013.
IFRS 11 – Joint Arrangements. IFRS 11 requires a venturer to classify its interest in a joint arrangement as a joint venture or a joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers. The standard is effective for annual periods beginning on or after January 1, 2013.
IFRS 12 – Disclosure of Interests in Other Entities. IFRS 12 applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. This standard is effective for annual period beginning on or after January 1, 2013.
IFRS 13 – Fair Value Measurements. IFRS 13 defines fair value, sets out in a single IFRS framework for measuring value and requires disclosure about fair value measurements. IFRS 13 applies to IFRSs that require or permit fair value measurements or disclosures about fair value measurement, except in specified circumstances. The standard is effective for annual periods beginning on or after January 1, 2013.
The Company has not completed its assessment of the impact of the above standards.
CONTROLS AND PROCEDURES
The Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICOFR”) as defined in National Instrument 52-109 Certification of Disclosure in Issuer–s Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.
The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company–s CEO and CFO have concluded, based on their evaluation at the financial year end of the Company, that the Company–s disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer is made known to them by others within the Company.
The ICOFR have been designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. The CEO and CFO have evaluated and tested the design and operating effectiveness of Anderson–s ICOFR as of December 31, 2012 and have concluded that these internal controls are designed properly and are effective in the preparation of financial statements for external purposes in accordance with IFRS. The CEO and CFO are required to cause the Company to disclose any change in the Company–s ICOFR that occurred during the period beginning on October 1, 2012 and ending on December 31, 2012 that has materially affected, or is reasonably likely to materially affect, the Company–s ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect the Company–s ICOFR.
It should be noted a control system, including the Company–s DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.
BUSINESS RISKS
Oil and gas exploration and production is capital intensive and involves a number of business risks including, without limitation, the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The price of natural gas has weakened due to increasing U.S. gas production driven primarily by the U.S. shale gas plays. The large amount of gas in storage combined with strong U.S. gas production and financial market fears has continued to suppress the price of natural gas. Oil prices continue to remain volatile as they are a geopolitical commodity, affected by concerns about economic markets in the U.S. and Europe and continued instability in oil producing countries. Differentials between WTI oil prices and prices received in Alberta are volatile. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company–s most recent Annual Information Form filed with Canadian securities regulatory authorities on SEDAR.
The Company makes substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves. As the Company–s revenues may decline as a result of decreased commodity pricing, it may be required to reduce cap