CALGARY, ALBERTA–(Marketwired – Nov. 12, 2014) – Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) announces its operating and financial results for the third quarter ended September 30, 2014.
- Funds from operations were $2.3 million in the third quarter of 2014, up 64% from the third quarter of 2013. Funds from operations were $13.3 million in the first nine months of 2014, up 15% from the same period of 2013.
- The operating netback was $22.58 per BOE in the third quarter of 2014, up 27% from the third quarter of 2013. The operating netback was $28.74 per BOE in the first nine months of 2014, up 23% from the same period of 2013.
- Operating costs were $13.52 per BOE in the third quarter of 2014, a 7% improvement from the $14.47 per BOE incurred in the third quarter of 2013.
- The average initial production rate over the first 30 days for the eight Cardium horizontal wells drilled in the 2013/2014 program was 511 BOED.
- During the third quarter of 2014, Anderson began its 2014/2015 drilling program. The program is currently planned to consist of 13 horizontal wells, 12 wells in the Cardium formation and one well in the Glauconite formation. As of November 10, 2014, six gross (5.5 net capital, 5.1 net revenue) wells have been drilled. Three 100% working interest wells in this program have been completed to date. The well with the most production history has an average initial production rate of 576 BOED (78% oil, condensate and NGL) over the first 16 days.
- Production in the third quarter of 2014 was 2,793 BOED (26% oil, condensate and NGL), consistent with the Company’s 2014 third quarter budget BOED estimate. Production from the new fall/winter 13-well program did not impact third quarter results but are expected to materially affect the next two quarters operating and financial results.
- The Company’s 2014 annual production guidance is 3,200 BOED (34% oil, condensate and NGL). Exit production guidance for 2014 remains unchanged at 3,700 BOED (42% oil, condensate and NGL).
- The Company spent $9.4 million on capital projects in the third quarter of 2013, compared to $3.8 million (net of minor property dispositions) in the second quarter of 2014.
- The Company has increased its 2014 capital budget to $52 million from $46 million.
- The Company’s horizontal drilling inventory as of November 10, 2014 is 122 gross (79.7 net) Cardium, Glauconite and Belly River locations.
FINANCIAL AND OPERATING HIGHLIGHTS
|Three months ended September 30||Nine months ended September 30|
|(thousands of dollars, unless otherwise stated)||2014||2013||%
|Oil and gas sales (1)||$||10,159||$||13,287||(24||%)||$||39,322||$||45,766||(14||%)|
|Revenue, net of royalties (1)||$||9,178||$||11,949||(23||%)||$||35,883||$||41,562||(14||%)|
|Funds from operations (2)||$||2,315||$||1,408||64||%||$||13,311||$||11,595||15||%|
|Funds from operations|
|per share(2) – basic and diluted||$||0.01||$||0.01||–||$||0.08||$||0.07||14||%|
|Adjusted loss before taxes (3)||$||(2,953||)||$||(5,856||)||50||%||$||(3,402||)||$||(14,641||)||77||%|
|Adjusted loss before taxes|
|per share(3) – basic and diluted||$||(0.01||)||$||(0.03||)||67||%||$||(0.02||)||$||(0.08||)||75||%|
|Loss per share|
|Basic and diluted||$||(0.01||)||$||(0.28||)||96||%||$||(0.02||)||$||(0.60||)||97||%|
|Capital expenditures (net of proceeds on dispositions)||$||9,371||$||229||3,992||%||$||29,209||$||8,077||262||%|
|Bank loans and other adjusted working capital (deficiency)(2)||$||(6,630||)||$||16,499||(140||%)|
|Average shares outstanding (thousands):|
|Basic and diluted||172,550||172,550||–||172,550||172,550||–|
|Ending shares outstanding (thousands)||172,550||172,550||–|
|Average daily sales volumes:|
|Oil and condensate (bpd)||568||1,061||(46||%)||806||1,305||(38||%)|
|Natural gas (Mcfd)||12,323||13,119||(6||%)||12,525||14,157||(12||%)|
|Barrels of oil equivalent (BOED) (4)||2,793||3,449||(19||%)||3,055||3,854||(21||%)|
|Oil and condensate ($/bbl)||$||96.17||$||100.14||(4||%)||$||99.34||$||90.77||9||%|
|Natural gas ($/Mcf)||$||3.93||$||2.27||73||%||$||4.49||$||2.86||57||%|
|Barrels of oil equivalent ($/BOE) (4)||$||39.54||$||41.87||(6||%)||$||47.15||$||43.49||8||%|
|Realized gain (loss) on derivative contracts ($/BOE)||$||0.51||$||(5.05||)||110||%||$||(0.66||)||$||(2.71||)||76||%|
|Operating costs ($/BOE)||$||13.52||$||14.47||(7||%)||$||13.33||$||13.01||2||%|
|Transportation costs ($/BOE)||$||0.13||$||0.36||(64||%)||$||0.30||$||0.32||(6||%)|
|Operating netback ($/BOE) (3)||$||22.58||$||17.77||27||%||$||28.74||$||23.46||23||%|
|Wells drilled (gross)||2.0||–||100||%||7.0||2.0||250||%|
|(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 and adjusted 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.|
The Company embarked on a new 13-well horizontal drilling program in the third quarter of 2014 that is expected to be completed by the first quarter of 2015. Production from the 13-well program started six weeks later than expected due to delays in obtaining Crown surface access approvals, as well as winter-like weather conditions in early September. Consequently, these wells will not impact the Company’s operating results until the fourth quarter of 2014 and the first quarter of 2015. Initial production from the new drilling program was recorded late in October 2014.
As of November 10, 2014, six gross (5.5 net capital, 5.1 net revenue) wells have been drilled, of which three gross (3.0 net) wells have been completed and placed on continuous production. Of the wells completed for production, two are Cardium and one is Glauconitic. Due to the lateness of the program, only one well has surpassed seven days of production and its initial rate for 16 days has been 576 BOED (78% oil, condensate and NGL). The remaining three gross (2.1 net revenue) wells that have been drilled are scheduled to be completed in the next two weeks, one of which is a 32 stage horizontal frac completion of a Cardium long-reach well. The drilling and completion costs for typical Cardium wells continue to average approximately $2.3 to $2.5 million per well.
The capital budget for 2014 has been increased to $52 million from the previously announced $46 million. The increase in the capital budget is attributable to the acquisition of partner interests through penalty account pick-up and farm-in transactions that increased Cardium net well counts, the unbudgeted expansion of the Willesden Green 5-14 gathering system to accommodate a significant condensate and NGL-rich gas discovery, the upgrade of the 5-14 liquids handling system, undeveloped land acquisitions and a cost overrun on the Company’s first Glauconite well. Also, some capital budget expenditures have been shifted from the first quarter of 2015 to the fourth quarter of 2014. Overall, the Company’s net well count has not changed for the fall/winter 2014/2015 program. However, the number of net wells planned to be drilled in the last half of 2014 has increased and the number of net wells planned to be drilled in the first quarter of 2015 has decreased from original budget expectations due to drilling higher working interest wells in the fourth quarter of 2014. The 2015 capital budget will be released in early 2015.
The Company’s guidance for 2014 annual and exit BOED production remains unchanged at 3,200 and 3,700 BOED respectively. However, due to delays in beginning the 13-well drilling program, the percentage contribution from oil, condensate and NGL has been reduced from 36% to 34%. The Company maintains its 2014 exit percentage contribution from oil, condensate and NGL at 42%.
Anderson’s focus area and prospects are located in Willesden Green, Buck Lake and West Pembina in west central Alberta. The Company’s efforts are dedicated to drilling horizontal wells in the Cardium, Glauconite and Belly River formations. Since completion of the strategic alternatives process in the fourth quarter of 2013, the Company has been growing production from these zones, with the goal of increasing the percentage of oil, condensate and NGL (collectively, “liquids”) production to over 50% of total production. In 2014, the Company estimates that liquids will make up approximately 34% of total production and over 60% of total revenue. By the end of 2015, the Company estimates that approximately 50% of total production and over 70% of total revenue will come from liquids(1). A strategy of increasing liquids production will increase annual cash flow per share faster than BOED production per share, due to the higher prices associated with these products. Over time, it will also increase the Company’s asset value and borrowing base.
Anderson prides itself on being one of the lowest capital cost operators in the Cardium horizontal play, with drilling and completion costs of $2.3 to $2.5 million per well for typical horizontal wells. The Company uses this capital cost measure to compare itself to other operators as it is well understood in the industry. Equipping and tie-in costs will vary much more from area to area. Currently, the Company has identified 79.7 net locations in the Cardium, Glauconite and Belly River formations, representing more than five years of drilling inventory. The Company’s goal is to continue to add to these locations in order to maintain this five to six year drilling inventory.
The Company has a goal of achieving an average horizontal well payout of one year by continuing to improve upon the profitability of the entire operation. Anderson will focus on keeping capital costs low, controlling infrastructure to keep operating costs low, and using available technology to pursue good reservoir rock and improve frac effectiveness. The Company plans to continue to use commodity price hedging to protect its capital program when it is considered prudent to do so.
Recent technological changes include repositioning the trajectory of horizontal wells within the Cardium zone to maximize frac effectiveness and using dissolvable frac balls.
The horizontal portion, or length, of a typical horizontal well is generally confined to one section of land, or one square mile. A typical horizontal well will have approximately 1,200 meters to 1,400 meters as its horizontal length. In contrast, the Company has recently drilled its first “long-reach” horizontal well which traversed approximately 2,600 meters of horizontal well length for a total well measured depth of 4,676 meters. The long-reach horizontal well is expected to access Cardium reserves in two sections of land once the well is completed, which is scheduled for later this month. This well was drilled and cased in 20 days, compared to 10 to 12 days for a typical horizontal well.
There is a capital cost benefit to drilling a long-reach well over two sections as compared to drilling two typical horizontal wells, each confined to one section of land. There also is a reserves benefit with longer horizontal wells due to additional reservoir contact. Typical horizontal well densities in Willesden Green vary from three to six wells per section of land.
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 to reduce overall operating costs. Currently, the Company operates over 90% of its production and all of its current drilling operations.
Anderson has commenced drilling on its Glauconite oil shoreface play in the Willesden Green area. While this play is new to the Company, other operators have been successfully drilling horizontal oil wells into the Glauconite oil shoreface in Willesden Green.
The Company has approximately 1,000 BOED of legacy shallow gas production and will continue to look for ways to optimize, rationalize, consolidate and improve the profitability of the shallow gas business. Anderson has an extensive drilling inventory of shallow gas opportunities and may sell some or all of these shallow gas assets.
The Company has no plans to buy back common shares or convertible debentures with normal course issuer bids. The Company’s business plan is to invest in its asset base, grow its asset base, cash flow and reserves and increase its financial flexibility. At September 30, 2014, the Company had $8.0 million in cash. Its bank line is $31 million and it currently has no bank loans outstanding. The 2014 capital budget of $52 million is being funded with cash, cash flow and available bank lines.
DRILLING PROGRAM UPDATE
The Company originally planned to drill 14 gross (11.5 net capital, 11.1 net revenue) wells from the third quarter of 2014 through the first quarter of 2015. With the changes in working interests due to farm-ins and the acquisition of additional interests from partners, the plan has been amended to drill 13 gross (11.3 net capital, 10.2 net revenue) wells over the same period of time.
As of November 10, 2014, Anderson has drilled six wells under this 2014/2015 drilling program, of which three have been recently completed. None of the wells have been on-stream long enough to have 30 days of initial production history.
In the second quarter of 2014, the Company completed the eighth well of the previous 2013/2014 drilling program, and the 30 day initial production (“IP”) results from those eight wells are shown in table below:
|Average initial production for the first 30 days (“IP 30”)|
|Barrels of oil and condensate per day (bpd)||240|
|Barrels of oil, condensate and NGL per day (bpd)||272|
|Barrels of oil equivalent per day (BOED)||511|
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.
HORIZONTAL DRILLING INVENTORY
The Company’s undeveloped horizontal drilling inventory at November 10, 2014, is outlined below:
|Prospect area (number of drilling locations)||Gross||Net*|
|Willesden Green Cardium||86||62.6|
|West Pembina/Buck Lake Cardium||26||7.8|
|Willesden Green Glauconite||8||8.0|
|Total horizontal drilling inventory||122||79.7|
* Net is net revenue interest
GLJ Petroleum Consultants Ltd. (“GLJ”) booked undeveloped reserves to 22.4 net locations as of April 30, 2014. GLJ’s booked locations are included in the drilling inventory table above.
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, although encouraging, has not demonstrated the play to be commercially viable at this time and, therefore, these locations are not included in the above table.
The Company has an extensive shallow gas drilling inventory in the Edmonton Sands formation. At the present time, the Company’s business strategy does not include any near-term plans for shallow gas drilling.
A comparison of Anderson’s average oil and condensate price to various market prices is presented below. Average prices are before the impact of any financial derivative contracts used for risk management. The difference between Anderson’s realized price and WTI Canadian is due to the price differential between Cushing, Oklahoma and Edmonton, Alberta, product transportation costs from the field to Edmonton, and adjustments for product quality.
CRUDE OIL AND CONDENSATE PRICES
|Three months ended
|Nine months ended
|WTI – $US||$||97.21||$||105.82||$||99.60||$||98.17|
|WTI – $Cdn||$||105.76||$||109.99||$||108.96||$||100.58|
|Differential from Cushing to Edmonton – $US per bbl||$||7.92||$||4.70||$||7.46||$||5.08|
|Edmonton Par – $Cdn per bbl||$||97.03||$||104.90||$||100.90||$||95.50|
|Anderson average oil price per bbl||$||95.66||$||100.81||$||98.73||$||90.71|
|Anderson average oil and condensate price per bbl*||$||96.17||$||100.14||$||99.34||$||90.77|
*Condensate includes field condensate and plant condensate.
The 2014 monthly WTI Canadian oil prices were approximately $94.57 per bbl in October and $88.75 per bbl to date in November. Differentials from Cushing, Oklahoma to Edmonton, Alberta were approximately $4.54 US per bbl in October and $5.30 US per bbl in November.
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 $3.88 per Mcf in the third quarter of 2014.
The average heat content of the Company’s natural gas has increased from 1,018 Btu/scf in the fourth quarter of 2013 and 1,026 Btu/scf in the first quarter of 2014 to 1,061 Btu/scf in the second quarter of 2014 and 1,065 Btu/scf in the third quarter of 2014 due to the new Cardium gas having higher heat content than the legacy shallow gas production. Natural gas is sold on the basis of heat content; therefore, higher heat content gas will yield higher prices per unit of measured volume.
NATURAL GAS PRICES
|Three months ended
|Nine months ended
|NYMEX $US per MMBtu||$||3.94||$||3.55||$||4.41||$||3.68|
|AECO $CAD per GJ||$||3.81||$||2.31||$||4.53||$||2.89|
|AECO $CAD per MMBtu||$||4.02||$||2.44||$||4.78||$||3.05|
|Anderson average plant gate price per Mcf||$||3.95||$||2.27||$||4.65||$||2.86|
AECO natural gas prices were approximately $3.48 per GJ ($3.68 per MMBtu) in October and $3.60 per GJ ($3.80 per MMBtu) to date in November.
Financial results compared to the prior year reflect the progress made to date since completion of the strategic alternatives process in the fourth quarter of 2013. However, production and revenue results in third quarter of 2014 were lower than the second quarter of 2014 due to less drilling activity, anticipated declines in flush production rates from the eight wells drilled in late 2013 and early 2014, lower commodity prices, and various shut-ins for plant maintenance over the summer months. Third quarter production on a BOED basis was in line with budget estimates as stronger than expected natural gas production from Cardium gas discoveries in the second quarter offset the impact of the delayed 13-well drilling program.
Funds from operations were $2.3 million in the third quarter of 2014 compared to $1.4 million in the third quarter of 2013 and $5.5 million in the second quarter of 2014.
On a BOE basis, oil and gas sales averaged $39.54 per BOE in the third quarter of 2014 compared to $41.87 per BOE in the third quarter of 2013 and $47.13 per BOE in the second quarter of 2014. During the third quarter of 2014, liquids revenue (oil, condensate and NGLs) represented 56% of total oil and gas sales. The Company’s operating netback was $22.58 per BOE in the third quarter of 2014 compared to $17.77 per BOE in the third quarter of 2013 and $28.88 per BOE in the second quarter of 2014. The decrease from the second quarter of 2014 was due to lower natural gas prices and a lower percentage of liquids volumes in the third quarter. Anderson’s operating netback for Cardium properties in the third quarter of 2014 was $41.09 per BOE, exclusive of hedging, compared to $44.74 per BOE in the second quarter of 2014, and $49.73 per BOE in the third quarter of 2013.
|)||Average oil and
Capital expenditures, net of dispositions, were $29.2 million for the nine months ended September 30, 2014. Field capital expenditures were $8.6 million in the third quarter of 2014 compared to $3.0 million in the second quarter of 2014. Capital investments in the second and third quarters of 2014 were focused primarily on the drilling, completion, equipping and tie-in of Cardium horizontal wells, the drilling of one Glauconite horizontal well, and the completion of the Willesden Green plant and gathering system upgrade. In the first nine months of 2014, the Company completed $2.5 million in net property acquisitions related to Cardium and Glauconite prospects, and the sale of $1.0 million in shallow gas assets and undeveloped land.
At September 30, 2014, the following derivative contracts were outstanding and recorded at estimated fair value:
Natural gas – fixed price swap contract based on the AECO 5A natural gas price:
|Period||Weighted average volume (GJ/d)||Weighted average AECO price ($/GJ)|
|October 1, 2014 to December 31, 2014||2,500||$||3.55|
Crude oil – fixed price swap contract based on WTI Canadian oil price:
|Period||Weighted average volume (bpd)||Weighted average WTI Cdn price ($/bbl)|
|October 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.
Recent dramatic oil price downswings and the negative impact on financial markets have pushed the Company’s share price lower, but have not had a negative impact on its business strategy as a whole. The Company’s wellhead oil price per barrel in the fourth quarter to date is very similar to what the Company experienced in the fourth quarter of 2013, which is still an economic oil price for the Company’s business.
Anderson is continuing with its significant high impact Cardium and Glauconite horizontal drilling program. The Company continues to rationalize and improve the profitability of its shallow gas assets and add to its horizontal drilling inventory with farm-ins and property acquisitions. The management and staff are very excited about the results to date of the fall/winter 13-well drilling program, the remainder of this drilling program and the expected future oil production growth in the fourth quarter of 2014 and first quarter of 2015.
For further information on the Company, please refer to the investor presentation at www.andersonenergy.ca.
Brian H. Dau, President & Chief Executive Officer
November 12, 2014