CALGARY, ALBERTA–(Marketwired – May 13, 2014) – Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) announces its operating and financial results for the first quarter ended March 31, 2014.
- The average initial production rate over the first 30 days for the seven Cardium horizontal light oil wells drilled in the winter program was 459 BOED per well.
- Production in the first quarter of 2014 was 2,958 BOED of which 39% was oil and NGL compared to 2,112 BOED (26% oil and NGL) for the fourth quarter of 2013 (net of properties sold in the fourth quarter of 2013).
- Funds from operations were $5.5 million in the first quarter of 2014 compared to negative funds from operations of $0.3 million in the fourth quarter of 2013.
- The operating netback was $34.51 per BOE in the first quarter of 2014 compared to $12.35 per BOE in the fourth quarter of 2013 (adjusted for properties sold in the quarter).
- The Board of Directors has approved a 2014 capital budget of $46 million. Annual production for 2014 is estimated to average approximately 3,200 BOED (36% oil and NGL). Exit production for 2014 is estimated to be approximately 3,700 BOED (42% oil and NGL). In addition to the seven wells drilled this winter, the Company is planning to drill 15 gross (12.6 net) Cardium and Mannville light oil horizontal wells from the second quarter of 2014 to spring breakup 2015.
- GLJ Petroleum Consultants (“GLJ”) have completed an interim reserves report of all of the Company’s oil and natural gas properties effective April 30, 2014. This report includes the impact of the winter drilling program, a positive change in the GLJ price deck and is net of production to April 30, 2014. Proved developed producing (“PDP”), total proved (“TP”) and total proved plus probable(“P&P”) BOE reserves were 11%, 3% and 9% higher than reported at year end 2013.
- At April 30, 2014, the Company had 3,811 MBOE PDP reserves (33% oil and NGL), 5,472 MBOE TP reserves (36% oil and NGL) and 9,583 MBOE P&P reserves (43% oil and NGL).
- Anderson’s total P&P pre-tax 10% net present value (“NPV 10”) of reserves at April 30, 2014 was $132.8 million, a 32% increase over the reported December 31, 2013 value. Undeveloped land was valued at $3.4 million at December 31, 2013.
- Cardium P&P reserves were 6.1 MMBOE representing 63% of total P&P reserves volumes and 82% of total P&P NPV 10 reserves value.
- The Company has agreed to an increase its bank facility from $28 million to $ 31 million, subject to customary closing conditions. As of today’s date, the Company is not drawn on its bank facility.
- 115 gross (73.3 net) light oil horizontal drilling locations have been identified in the Cardium and Mannville zones. Only 31% of the net locations are recognized as P&P locations in the interim reserves report. Approximately 97% of the net locations are Company operated.
FINANCIAL AND OPERATING HIGHLIGHTS
|Three months ended March 31|
|(thousands of dollars, unless otherwise stated)||2014||2013||%
|Oil and gas sales (1)||$||14,522||$||16,863||(14%||)|
|Revenue, net of royalties (1)||$||13,195||$||15,268||(14%||)|
|Funds from operations (2)||$||5,538||$||5,486||1%|
|Funds from operations per share|
|Basic and diluted (2)||$||0.03||$||0.03||–|
|Adjusted earnings (loss) before taxes (3)||$||544||$||(5,113||)||111%|
|Adjusted earnings (loss) before taxes|
|per share – basic and diluted(3)||$||–||$||(0.03)||100%|
|Earnings (loss) per share|
|Basic and diluted||$||–||$||(0.03||)||100%|
|Capital expenditures (net of proceeds on dispositions)||$||16,032||$||7,662||109%|
|Bank loans and other working capital (deficiency) (2)||$||(993)||$||(66,783||)||99%|
|Average shares outstanding (thousands):|
|Ending shares outstanding (thousands)||172,550||172,550||–|
|Average daily sales volumes:|
|Natural gas (Mcfd)||10,920||14,759||(26%||)|
|Barrels of oil equivalent (BOED) (4)||2,958||4,191||(29%||)|
|Natural gas ($/Mcf)||$||5.01||$||2.94||70%|
|Barrels of oil equivalent ($/BOE) (4)||$||54.54||$||44.70||22%|
|Realized loss on derivative contracts ($/BOE)||$||(1.53||)||$||(1.55||)||1%|
|Operating costs ($/BOE)||$||13.28||$||11.93||11%|
|Transportation costs ($/BOE)||$||0.23||$||0.21||10%|
|Operating netback ($/BOE) (3)||$||34.51||$||26.78||29%|
|Wells drilled (gross)||4||2||100%|
|(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. Bank loans of $nil (March 31, 2013 – $55.1 million) were included in working capital as defined therein.|
|(3)||Adjusted earnings (loss) before taxes, adjusted earnings (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.|
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. Coming out of the strategic alternatives process, the Company is smaller in terms of production, has cash in the bank and an unused bank operating line. Its convertible debentures mature in 2016 and 2017.
Admittedly, the current share price is weak. The overall market for public junior oil and gas companies has been weak in the past few years. The 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 and Mannville horizontal light oil wells, and growing its Cardium and Mannville horizontal oil drilling inventory in the Willesden Green, West Pembina and Buck Lake areas. In its first full quarter since completion of the strategic alternatives process, the Company has shown progress on all fronts with increasing oil production, cash flow and reserves. The Company expects it will take time for the market to appreciate the growth in annual oil production and growth potential of its asset base. 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. A strategy of increasing oil assets, production and cash flow should also support a higher borrowing base over time.
Anderson will continue to focus on reducing average well payouts. The goal is to have Cardium wells pay out in approximately one year, on average, by continuing to improve the profitability of these operations. The Company believes this goal can be achieved by continuing to implement new approaches in Cardium horizontal drilling and completion technologies, and by keeping costs as low as possible.
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 long-reach horizontal wells 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.
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. Currently, the Company operates over 90% of its production and all of its current drilling operations.
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 2014.
The Company currently has no plans to dispose of its Cardium oil assets. In addition, the Company currently has no plans to buy back common shares or convertible debentures with normal course issuer bids. The Company’s plan is to continue to grow its asset base by investing in its light oil drilling opportunities.
Anderson will continue to look for ways to optimize, rationalize, consolidate and improve the profitability of its shallow gas business. In the fourth quarter of 2013 and the first quarter of 2014, the Company disposed of unprofitable shallow gas assets. The Company’s remaining shallow gas properties are profitable at current natural gas prices. The Company is not planning any significant new investments in the shallow gas business, and may dispose of some or all of its remaining shallow gas assets.
For 2014, the Company estimates that oil and NGL (“liquids”) production will be approximately 36% of total production, and that revenue from liquids will be approximately 66% of total revenue. The Company expects the percentage contribution of liquids to total revenue to grow, and estimates that its production will be balanced between natural gas and liquids by the end of 2015.
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, but were delayed due to a third party natural gas plant that incurred a plant outage which lasted almost a month. The third party plant processed the solution gas from these two wells. This outage was resolved and these two oil wells and the related solution gas were brought on-stream a month later than planned. The other five wells in the program were unaffected by the third party plant outage.
The best performing well to date 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 initial production (“IP 30”). This well has demonstrated the best IP 30 performance of any horizontal well drilled by the Company since its entry into the Cardium play in 2010.
Results from the program to date are shown in table below:
|Average Gross IP 30|
|Number of wells in average||7|
|Barrels of oil per day (BOPD)||241|
|Barrels of oil and NGL per day (BPD)||276|
|Barrels of oil equivalent per day (BOED)||459|
The comparable IP 30 data for the Company’ previous slick water drilling program was 453 BOED for seven wells.
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 may vary.
In its March 31, 2014 press release, the Company reported the potential for a 1 MMcfd production shut-in related to a National Energy Board Order imposing a reduction in TransCanada Pipelines’ maximum operating pressure on a pipeline lateral in Central Alberta. The Operator of the gas plant on the pipeline lateral has since informed the Company that the Company will not have its production curtailed by this Order. The Company will continue to monitor this situation.
LIGHT OIL HORIZONTAL DRILLING INVENTORY
The Company’s undeveloped light oil horizontal drilling inventory at May 12, 2014, is outlined below:
|Prospect Area (number of drilling locations)||Gross||Net*|
|Willesden Green Cardium||81||58.3|
|West Pembina/Buck Lake Cardium||26||7.7|
|Total Light Oil Horizontal Drilling Inventory||115||73.3|
|* Net is net revenue interest|
GLJ booked undeveloped reserves to 22.4 net locations at April 30, 2014. The locations booked by GLJ include 1.8 net locations related to the Mannville/Belly River prospect area. GLJ’s booked locations are included in the drilling inventory table shown above.
Six gross (3.2 net) locations are on lands where the Company’s development plan is to drill extended reach horizontal wells traversing 1.5 to 2 miles 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; 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 AND DISPOSITIONS
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 $3.1 million. These lands had no further development potential.
Year-to-date, the Company has completed or committed to $1.9 million in net property acquisitions related to Cardium and Mannville prospects, and the sale of $0.9 million in shallow gas and undeveloped land.
2014 CAPITAL BUDGET
The Board of Directors has approved a 2014 capital budget of $46 million. Sixty-eight percent of the budget is directed at drilling and completion expenditures to drill 12 net Cardium and Mannville horizontal light oil drilling prospects. Twenty-four percent of the expenditures are directed at equipping, tie-in and facility expenditures and the remaining funds are directed at land, abandonments and capitalized G&A expenditures. With this capital program, the annual production guidance for 2014 has increased to approximately 3,200 BOED (36% oil and NGL), up from the guidance provided by Company in its March 31, 2014 press release (2,600 BOED, 33% oil and NGL). The Company estimates 2014 exit production to be approximately 3,700 BOED (42% oil and NGL).
In addition to the seven well 2013/2014 Cardium winter program, the Company is planning to drill 15 gross (12.6 net) Cardium and Mannville light oil horizontal wells from the second quarter of 2014 to spring breakup 2015. The Company continues to evaluate farm-in and property acquisitions in its Cardium and Mannville light oil focus areas. Should the Company add additional farm-in commitments, it would substitute those commitments into its 2014 capital program and defer the current budgeted locations until 2015.
A comparison of Anderson’s average wellhead oil price to various market prices is presented below. Average wellhead prices are before the impact of any financial derivative contracts used for risk management. 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.
CRUDE OIL PRICES
|Three months ended
|WTI – $US||$||98.62||$||94.34|
|WTI – $Cdn||$||108.83||$||95.16|
|Differential from Cushing to Edmonton – $US per bbl||$||8.35||$||6.91|
|Edmonton Par – $Cdn per bbl||$||100.04||$||88.31|
|Anderson average wellhead price per bbl||$||97.36||$||84.83|
A comparison of Anderson’s average plant gate natural gas price to various market prices is presented below. Average plant gate prices are before the impact of any financial derivative or fixed price contracts used for risk management. The difference between the AECO price and Anderson’s plant gate price is due to transportation costs and the heat content of the gas. Financial derivative and fixed price contracts reduced the average price received for natural gas to $4.59 per Mcf in the first quarter of 2014.
NATURAL GAS PRICES
|Three months ended
|NYMEX US$ per MMBtu||$||4.72||$||3.48|
|AECO $CAD per GJ||5.36||3.04|
|AECO $CAD per MMBtu||5.66||3.20|
|Anderson average plant gate price per Mcf||$||5.38||$||2.94|
The 2014 monthly WTI Canadian oil prices were approximately $112.14 per bbl in April and $109.12 per bbl to date in May. Differentials from Cushing, Oklahoma to Edmonton were approximately $8.32 US per bbl in April and $4.12 US per bbl in May. AECO natural gas prices were approximately $4.52 per GJ ($4.77 per MMBtu) in April and $4.45 per GJ ($4.69 per MMBtu) month to date in May.
Going forward, Anderson estimates that light oil prices will stay strong but volatile and will be influenced by geopolitical events. Cushing, Oklahoma to Edmonton differentials are also expected to continue to be volatile, as well as movements in the US dollar exchange rate.
In the first quarter of 2014, North American winter weather contributed to much stronger natural gas pricing than we have seen in recent years. The winter weather also reduced North American natural gas storage to levels not seen for many years. This should contribute to stronger natural gas pricing this summer compared to recent prior years.
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.
Funds from operations were $5.5 million in the first quarter of 2014 as compared to $(0.3) million in the fourth quarter of 2013. On a BOE basis, oil and gas sales averaged $54.54 per BOE in the first quarter of 2014 compared to $36.49 per BOE in the fourth quarter of 2013. During the first quarter of 2014, oil and NGL revenue represented 66% of total revenue. The Company’s operating netback was $34.51 per BOE in the first quarter of 2014 as compared to $14.81 per BOE for the fourth quarter of 2013 ($12.35 per BOE excluding properties sold in the fourth quarter of 2013). Both quarters were negatively impacted by losses on financial derivative or fixed price contracts (2014 – $2.91 per BOE, 2013 – $2.96 per BOE). The increase in operating netback was primarily driven by higher oil and gas prices. Anderson’s operating netback for Cardium properties in the first quarter of 2014 was $60.30 per BOE as compared to $39.54 per BOE in the fourth quarter of 2013 ($38.55 per BOE adjusted for properties sold in the fourth quarter of 2013), exclusive of hedging.
The Company reported earnings of $0.5 million in the first quarter of 2014 compared to a loss of $2.4 million in the fourth quarter of 2013 and a loss of $5.1 million for the first quarter of 2013.
Field capital expenditures were $14.5 million in the first quarter of 2014 as compared to $7.4 million in the fourth quarter of 2013. Capital investments in the first quarter of 2014 were focused primarily on the drilling, completion, equipping and tie-in of Cardium horizontal oil wells. In the first quarter of 2014, the Company spent $1.0 million net of dispositions on the acquisition of undeveloped land and producing properties as opposed to net dispositions of $79.8 million in the fourth quarter of 2013.
At March 31, 2014, the following fixed price swap contract based on the AECO 5A natural gas price was outstanding and recorded at estimated fair value:
|Period||Weighted average volume (GJ/d)||Weighted average Canadian ($/GJ)|
|April 1, 2014 to December 31, 2014||2,500||$||3.55|
Subsequent to March 31, 2014 the Company entered into the following derivative contract for crude oil:
|Period||Weighted average volume (bpd)||Weighted average WTI Canadian ($/bbl)|
|May 1, 2014 to December 31, 2014||500||$||110.00|
Fixed price contracts
The Company entered into physical contracts to sell 2,500 GJs per day of natural gas for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72 per GJ. All of the remaining natural gas production is being sold at the monthly average of AECO 5A daily index prices.
GLJ Petroleum Consultants (“GLJ”), an independent evaluator, has completed a modified corporate look-ahead analysis of the Company’s reserves (the “GLJ Interim Report”). The previous 2013 year end evaluation has been updated to an April 30, 2014 effective date, utilizing GLJ’s April 1, 2014 price deck and a modified “look ahead” analysis approach. More details on the methodology followed under this approach are provided in Management’s Discussion and Analysis for the three months ended March 31, 2014. The GLJ Interim Report was prepared for the Company for the purpose of providing a corporate update and is not the equivalent of a full year end reserves report. At April 30, 2014, the Company had 3,811 MBOE PDP reserves (33% oil and NGL), 5,472 MBOE TP reserves (36% oil and NGL) and 9,583 MBOE P&P reserves (43% oil and NGL). The GLJ price forecast used in the evaluation is shown in Management’s Discussion and Analysis for the three months ended March 31, 2014.
The increased reserves in the GLJ Interim Report reflect the impact of the winter drilling program, higher commodity price forecasts, and additional drilling locations associated with recent property acquisitions. The Cardium formation represents approximately 47%, 51% and 63% respectively of PDP, TP and P&P total BOE reserves volumes and 79%, 80% and 82% respectively of the total Company PDP, TP and P&P NPV 10 value.
SUMMARY OF OIL AND GAS RESERVES
|April 30, 2014||December 31, 2013|
|Gross Working Interest
Oil and Gas Reserves
|Gas (MMcf)||Total (MBOE)||Pre-tax NPV 10
|Gas (MMcf)||Total (MBOE)||Pre-tax NPV 10
|Proved developed producing||1,020||246||15,269||3,811||63,375||792||216||14,639||3,447||43,153|
|Proved developed non-producing||53||34||4,176||784||6,660||128||25||3,683||767||7,527|
|Proved plus probable||3,469||643||32,829||9,583||132,813||3,150||565||30,642||8,822||100,312|
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 was valued at $3.4 million by management at the end of 2013.
ANNUAL GENERAL MEETING
The Company’s annual shareholders’ meeting (the “Meeting”) is scheduled for 10:00 a.m. on June 18, 2014 at the Westwinds Conference Room, 2nd Floor Selkirk House, 555 4th Avenue S.W., Calgary, Alberta.
On May 12, 2014, the Company’s Board of Directors approved an advance notice by-law (the “By-Law”) which will apply to nominations of directors at the Meeting. The By-Law is in effect until it is confirmed, confirmed as amended or rejected by shareholders at the Meeting. Additional details will be provided in the Company’s management information circular to be distributed prior to the Meeting.
The Company has made considerable progress in the last few months by demonstrating oil production growth, oil reserves growth and reserves value growth. Anderson is now embarking on a significant high impact Cardium and Mannville horizontal oil drilling program. The Company continues to rationalize and improve the profitability of its shallow gas assets and add to its horizontal light oil drilling inventory with farm-in and property acquisitions. The management and staff are very excited about the future oil production growth drilling program and the Company’s prospects in the Willesden Green Cardium and Mannville plays.
For further information on the Company, please refer to the investor presentation at www.andersonenergy.ca.
Brian H. Dau, President & Chief Executive Officer
May 13, 2014