CALGARY, ALBERTA–(Marketwired – Nov. 12, 2015) – Anderson Energy Inc. (“Anderson” or the “Company”) (TSX:AXL) announces its operating and financial results for the third quarter ended September 30, 2015. The Company will be filing its unaudited condensed interim financial statements and management’s discussion and analysis (“MD&A”) for the three and nine months ended September 30, 2015 on SEDAR today. Copies can be found under the Company’s profile on www.sedar.com and on the Company’s website at www.andersonenergy.ca.
- Production for the first nine months of 2015 was 2,375 BOED (46% oil, condensate and NGL). Third quarter production was 2,167 BOED (45% oil, condensate and NGL), exceeding the earlier guidance of 1,800 to 2,000 BOED largely due to better than expected performance from the wells drilled during the 2014/2015 winter drilling program. Approximately 217 BOED of Cardium production was shut-in in the third quarter as a result of the TransCanada Pipelines Ltd. (“TCPL”) outages, compared to approximately 320 BOED in the first quarter and 125 BOED in the second quarter of 2015. Cardium production was 1,805 BOED (51% oil, condensate and NGL) in the third quarter of 2015.
- Funds from operations were $0.8 million in the third quarter of 2015 compared to $1.5 million in the second quarter of 2015 due to decreases in oil, condensate, and NGL prices in the third quarter. Oil and gas revenue per BOE decreased 12% from the second quarter of 2015 and decreased 24% from the third quarter of 2014. The operating netback was $18.92 per BOE in the third quarter of 2015 compared to $21.54 per BOE in the second quarter of 2015. The operating netback from Cardium properties in the third quarter of 2015 was $22.14 per BOE compared to $28.77 per BOE in the second quarter of 2015. Funds from operations were $4.17 per BOE in the third quarter of 2015. Funds from operations were $13.06 per BOE before convertible debenture interest costs.
- Operating expenses were $8.72 per BOE in the third quarter compared to $10.38 per BOE in the second quarter of 2015 and $13.52 per BOE in the third quarter of 2014. Savings in operating expenses were realized through a variety of corporate initiatives implemented in the second quarter of 2015. Operating expenses from Cardium properties in the third quarter of 2015 were $8.51 per BOE compared to $7.19 per BOE in the second quarter of 2015.
- As of September 30, 2015, the Company had no bank debt and positive adjusted working capital of $7.5 million (up from $4.4 million at the end of the second quarter of 2015).
- In the third quarter of 2015, the Company received net proceeds of $3.0 million on the sale of certain shallow gas assets that produced approximately 200 BOED (94% natural gas) in the eight months of 2015 prior to the date of disposition.
- The Company estimates production for the fourth quarter of 2015 to be approximately 1,850 BOED (45% oil, condensate and NGL), net of the production sold in the third quarter. Maintenance activities are expected to reduce fourth quarter production by approximately 90 BOED and TCPL outages are expected to reduce fourth quarter production by approximately 25 BOED.
- The average initial production rate over the first 30 days (“IP 30”) for the nine Cardium horizontal light oil wells drilled in the 2014/2015 winter drilling program was 413 BOED per well (85% oil, condensate and NGL). The program includes the Company’s first long-reach well which had an IP 30 of 651 BOED (92% oil, condensate and NGL). The best well in the program had an IP 30 of 707 BOED (71% oil, condensate and NGL).
- On November 9, 2015, the Company announced a proposed transaction to exchange all of its outstanding convertible debentures (the “Debentures”) for equity (the “Transaction”). If the Transaction is approved by the holders of the Debentures (the “Debentureholders”), the Company will exchange the entire principal amount of its 7.50% Series A convertible debentures and 7.25% Series B convertible debentures on the basis of a price of $0.0361 per common share, for approximately 2.659 billion common shares to be issued from treasury. If the Transaction is approved, it will simplify the capital structure of the Company, provide certainty with respect to the dilution resulting from the conversion of the Debentures into common shares, reduce financial risk for the Company in a difficult economic and commodity price environment and reduce interest costs by $7.1 million per year from 2015 levels, resulting in increased cash flow available to invest into Anderson’s high quality asset base. It will allow the Debentureholders to receive full face value recognition for their Debentures in common shares of the Company, as well as cash for the final interest payments. The Transaction will be voted on at a meeting of Debentureholders to be held in January 2016. If the proposal is not approved by the Debentureholders, the Company intends to exercise its rights to pay both the principal and accrued and unpaid interest on the Debentures in common shares on their maturity date or, in the case of the 7.25% Series B convertible debentures, the first available redemption date of June 30, 2016, pursuant to the terms of the indenture governing the Debentures.
FINANCIAL AND OPERATING HIGHLIGHTS
|Three months ended September 30||Nine months ended September 30|
|(thousands of dollars, unless otherwise stated)||2015||2014||%
|Oil and gas sales (1)||$||6,018||$||10,159||(41||%)||$||20,099||$||39,322||(49||%)|
|Revenue, net of royalties (1)||$||5,542||$||9,178||(40||%)||$||18,424||$||35,883||(49||%)|
|Funds from operations(2)||$||832||$||2,315||(64||%)||$||2,563||$||13,311||(81||%)|
|Funds from operations per share(2) – basic and diluted||$||–||$||0.01||(100||%)||$||0.01||$||0.08||(88||%)|
|Adjusted earnings (loss) before taxes (3)||$||(2,269||)||$||(2,953||)||23||%||$||17,994||$||(3,402)||629||%|
|Adjusted earnings (loss) before taxes per share(3) – basic and diluted||$||(0.01||)||$||(0.01||)||–||$||0.10||$||(0.02)||600||%|
|Loss per share|
|Basic and diluted||$||(0.20||)||$||(0.01||)||(1,900||%)||$||(0.08||)||$||(0.02)||(300||%)|
|Capital expenditures (net of proceeds on dispositions)||$||(2,420||)||$||9,371||(126||%)||$||(30,892||)||$||29,209||(206||%)|
|Adjusted working capital (deficiency) (2)||$||7,533||$||(6,630)||214||%|
|Average shares outstanding (thousands):|
|Basic and diluted||172,550||172,550||–||172,550||172,550||–|
|Ending shares outstanding (thousands)||172,550||172,550||–|
|Average daily sales:|
|Oil and condensate (bpd)||827||568||46||%||937||806||16||%|
|Natural gas (Mcfd)||7,203||12,323||(42||%)||7,737||12,525||(38||%)|
|Barrels of oil equivalent (BOED) (4)||2,167||2,793||(22||%)||2,375||3,055||(22||%)|
|Oil and condensate ($/bbl)||$||54.56||$||96.17||(43||%)||$||55.34||$||99.34||(44||%)|
|Natural gas ($/Mcf)||$||2.73||$||3.93||(31||%)||$||2.63||$||4.49||(41||%)|
|Barrels of oil equivalent ($/BOE) (4)||$||30.18||$||39.54||(24||%)||$||31.00||$||47.15||(34||%)|
|Realized gain (loss) on derivative contracts ($/BOE)||$||–||$||0.51||(100||%)||$||–||$||(0.66)||100||%|
|Operating costs ($/BOE)||$||8.72||$||13.52||(36||%)||$||9.87||$||13.33||(26||%)|
|Transportation costs ($/BOE)||$||0.15||$||0.13||15||%||$||0.27||$||0.30||(10||%)|
|Operating netback ($/BOE) (3)||$||18.92||$||22.58||(16||%)||$||18.28||$||28.74||(36||%)|
|Wells drilled (gross)||–||2||(100||%)||2||7||(71||%)|
(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 MD&A for a more complete description of these additional GAAP measures.
(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 continues to focus on its core Willesden Green area. This area currently represents over 85% of the Company’s production volumes and most of its high quality, low decline rate Cardium production.
Production was 2,375 BOED (46% oil, condensate and NGL) in the first nine months of the year and 2,167 BOED (45% oil, condensate and NGL) in the third quarter of 2015. Third quarter production exceeded the higher end of the Company’s earlier guidance of 1,800 to 2,000 BOED. TCPL outages were approximately 220 BOED in the first nine months of the year (217 BOED in the third quarter). The Company was able to mitigate the impact of TCPL outages in the second and third quarters of 2015 by moving firm service to different receipt points on the TCPL system.
With no new drilling since January 2015, production has declined during the year. In addition, the Company sold 500 BOED of production in late January, shut-in 177 BOED of shallow gas production in the first half of the year, and sold another 200 BOED production in late August. The Company estimates its fourth quarter production to be approximately 1,850 BOED (45% oil, condensate and NGL). Maintenance activities on two Cardium wells are expected to reduce fourth quarter production by approximately 90 BOED and TCPL outages are expected to reduce fourth quarter production by approximately 25 BOED. The greatest risk to the guidance is the extent and duration of these maintenance activities and the TCPL outages.
On December 15, 2014, TCPL issued a notice to all shippers upstream of James River, Alberta regarding the restriction of natural gas volume receipts to certain limits. As a result of the actions taken by TCPL, disruptions to pipeline transportation service in the affected areas (referred to as “outages”) resulted in restrictions on the Company’s production in various areas, including its Willesden Green Cardium area. The restrictions affect the production of oil, condensate and NGL as well as natural gas. The outages were initially expected to continue until October 30, 2015 but to date some restrictions continue to remain in place. TCPL has indicated that there will be periodic cutbacks in firm service for the upcoming winter for shippers north of James River. Restrictions on both firm and interruptible transportation may cause delays in drilling. Due to the fluctuating nature of the outages and the changing forecasts provided by TCPL, it is difficult to estimate the extent of the impact of the outages on the Company’s future results.
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 – $US||$||46.44||$||97.21||$||50.98||$||99.60|
|WTI – $Cdn||$||60.75||$||105.76||$||64.09||$||108.96|
|Differential from Cushing to Edmonton – $US per bbl||$||3.40||$||7.92||$||4.33||$||7.46|
|Edmonton Par – $Cdn per bbl||$||56.27||$||97.03||$||58.59||$||100.90|
|Anderson average oil price per bbl||$||55.11||$||95.66||$||55.73||$||98.73|
|Anderson average oil and condensate price per bbl*||$||54.56||$||96.17||$||55.34||$||99.34|
*Condensate includes field condensate and plant condensate.
The 2015 monthly WTI Canadian oil prices were approximately $60.51 per bbl in October and $59.40 per bbl to date in November. Differentials from Cushing, Oklahoma to Edmonton are approximately $2.88 US per bbl in October, $2.03 US per bbl for November and $2.23 per bbl to date for December.
Going forward, light oil prices are expected to remain weak in the short term due to crude oil inventory levels being at their highest level on record in the US. Over the long term, prices will continue to be volatile and will be influenced by the balance between supply and demand, and by geopolitical events. Cushing, Oklahoma to Edmonton, Alberta differentials will continue to be volatile, as well as movements in the US/Canadian dollar exchange rate.
A comparison of Anderson’s average plant gate natural gas price to various market prices is presented below. Average plant gate prices are before the impact of any financial derivative or fixed-price contracts used for risk management. The difference between the AECO price and Anderson’s plant gate price is due to transportation costs and the heat content of the gas.
NATURAL GAS PRICES
|Three months ended
|Nine months ended
|NYMEX US$ per MMBtu||$||2.73||$||3.94||$||2.76||$||4.41|
|AECO $CAD per GJ||$||2.75||$||3.81||$||2.63||$||4.53|
|AECO $CAD per MMBtu||$||2.90||$||4.02||$||2.77||$||4.78|
|Anderson average plant gate price per Mcf||$||2.73||$||3.95||$||2.63||$||4.65|
AECO natural gas prices were approximately $2.46 per GJ ($2.60 per MMBtu) in October and $2.38 per GJ ($2.51 per MMBtu) to date in November.
Natural gas prices are influenced by weather events and are tempered by the increasing supply of new shale gas. Until meaningful exports of natural gas commence from North America through liquefied natural gas projects, the Company believes that natural gas prices will be range-bound by weather events.
COMMODITY HEDGING CONTRACTS
The Company has not hedged any crude oil or natural gas volumes at this time. The Company enters into hedging contracts to protect its capital program and continues to evaluate the merits of additional commodity hedging as part of a price management strategy.
Funds from operations were $0.8 million in the third quarter of 2015 compared to $1.5 million in the second quarter of 2015 and $2.3 million in the third quarter of 2014, and decreased from the third quarter of 2014 due to dramatic reductions in both oil and natural gas prices. Benchmark prices for oil were more than 40% lower in the third quarter of 2015 than they were in the third quarter of 2014. Benchmark prices for natural gas were more than 25% lower than they were last year.
On a per BOE basis, oil and gas revenue averaged $30.18 per BOE in the third quarter of 2015 compared to $34.48 per BOE in the second quarter of 2015. During the third quarter of 2015, oil, condensate and NGL revenue represented 70% of total revenue. The Company’s operating netback was $18.92 per BOE in the third quarter of 2015 compared to $21.54 per BOE for the second quarter of 2015. The decrease in operating netback in the third quarter was driven by lower oil, condensate and NGL prices as compared to the second quarter of 2015. Anderson’s operating netback for Cardium properties in the third quarter of 2015 was $22.14 per BOE compared to $28.77 per BOE in the second quarter of 2015.
The Company recorded a loss of $34.3 million in the third quarter of 2015 compared to loss of $4.1 million in the second quarter of 2015 and loss of $3.0 million for the third quarter of 2014. The Company recorded an impairment provision of $32.0 million against property, plant and equipment and a gain on sale of $2.0 million on the disposition of certain shallow gas assets in the third quarter of 2015. The Company recorded a gain on sale of $30.2 million related to the Arrangement in the first quarter of 2015.
Capital expenditures, before proceeds from dispositions, were $0.6 million in the third quarter of 2015. The Company terminated its drilling program in January 2015 due to the dramatic drop in commodity prices. Capital expenditures in the first nine months of 2015 were $7.4 million and were focused primarily on the drilling, completion, equipping and tie-in of Cardium horizontal oil wells.
COST SAVING MEASURES
1) General and administrative (“G&A”) expenses: In 2014, the Company’s gross G&A (cash) expenses were $8.3 million. Changes were made to the Company’s G&A in the first quarter of 2015 which are estimated to reduce G&A (cash) expenses by approximately $1.3 million in 2015 to approximately $7 million. Most of the reductions will impact the last three quarters of 2015. These changes include the cancellation of bonuses for management, the reduction in bonuses for staff, the reduction in other salary costs for both management and staff and the renegotiation of contracts for other services. Approximately 16% of the Company’s G&A (cash) expense is capitalized and the balance is expensed. Overhead recoveries are estimated to be similar to the prior year. The Company had approximately $0.5 million in gross non-cash stock based compensation costs in 2014, which is estimated to remain essentially unchanged in 2015.
2) Operating expenses: With the reduction in commodity prices, the Company has been focusing on reducing field operating expenses. A significant portion of the Company’s operating expenses are fixed and relates to legacy shallow gas assets. To date in 2015, the Company has sold 200 gross (109.4 net) wellbores and continues to actively abandon and reclaim uneconomic wells. This high-grading of the asset base has led to an expectation that operating costs will be reduced by 17% from $12.43 per BOE in 2014 to approximately $10.30 per BOE in 2015.
3) Capital expenditures: During past commodity price down cycles, the industry capitalized on the opportunity to make significant reductions in per unit capital costs to improve the economic equation. Similarly, the Company is taking steps to reduce costs during the current commodity price down cycle. The Company’s goal was to achieve average well payouts of approximately one year when oil prices were in the range of $90 to $100 US WTI per bbl. Today, the Company’s payout goal has not changed, but the Company needs to reduce capital costs, reduce operating costs in the field, and admittedly receive better oil pricing than it receives today. Anderson is looking at opportunities to re-engineer its completions operations and is also working with suppliers and service providers for improved cost efficiency and operations, and believes a 30% reduction in capital costs may be achievable as a result of these initiatives. The Company historically has been a leader in low-cost Cardium horizontal drilling and completions and is working towards achieving even lower costs.
The Company continues to look for additional ways to reduce costs in the current economic and commodity price environment.
2014/2015 WINTER DRILLING PROGRAM
The Company has completed its 2014/2015 winter drilling program with 9 gross (8.1 net capital, 7.0 net revenue) new Cardium oil wells. The nine Cardium oil wells drilled have more than 30 days of initial production and an average IP 30 of 413 BOED (85% oil, condensate and NGL). Included in the most recent drilling program was the Company’s first long-reach well which had an IP 30 of 651 BOED (92% oil, condensate and NGL). The best well in the nine-well program had an IP 30 of 707 BOED (71% oil, condensate and NGL).
Of the nine Cardium wells drilled in the 2014/2015 program, five are in the central land block, three are in the northern land block and one is in the southern land block of the greater Willesden Green area.
The IP 30 and product mix results from the Cardium wells in the 2014/2015 winter drilling program compares favorably with the 2013/2014 winter drilling program, which had an average IP 30 of 511 BOED (53% oil, condensate and NGL). A comparison of the oil, condensate and NGL components of the BOED production for the two drilling programs shows an average IP 30 of 349 barrels per day for the 2014/2015 program and 272 barrels per day for the 2013/2014 winter drilling program. Notwithstanding the market perception of the current oil price environment, oil, condensate and NGL remain more valuable than solution gas and a higher percentage of oil, condensate and NGL in the Company’s product mix can be more important to overall revenue and profitability than the overall BOED production rate.
The average IP 30 for the 19 Cardium wells completed with slick water fracture stimulation in the Willesden Green area on Company lands since June 2012 was 469 BOED (68% oil, condensate and NGL). The best single well IP 30 result from these wells was 1,119 BOED (67% oil, condensate and NGL). A recent industry publication indicated an industry average IP 30 of 322 BOED (60% oil, condensate and NGL) for the greater Willesden Green area since 2012.
By using selective positioning of the horizontal well trajectory, the Company is realizing higher IP 30 production rates than historical Willesden Green area industry averages. The Company has now adopted the use of dissolvable frac balls for toe fracs and has moved to less nitrogen usage in heel fracs. Other changes made this year include a redesigned stage tool to reduce mechanical wellbore failure.
LIGHT OIL HORIZONTAL DRILLING INVENTORY
The Company’s undeveloped light oil horizontal drilling inventory at November 12, 2015, after completion of the winter drilling program, is outlined below:
|Prospect Area (number of drilling locations)||Gross||Net*|
|Willesden Green Cardium||75||56.0|
|West Pembina/Buck Lake Cardium||26||7.8|
|Total light oil horizontal drilling inventory, November 12, 2015||107||69.8|
* Net is net revenue interest
GLJ Petroleum Consultants (“GLJ”), the Company’s independent reserves evaluator, booked undeveloped reserves to 22.7 net locations at December 31, 2014, of which 1.6 net locations were drilled in the first quarter of 2015 and the remaining 21.1 net locations are included in the table above.
PROPOSAL TO CONVERTIBLE DEBENTUREHOLDERS
The Company intends to mail a proposal to the holders of the Debentures (the “Debentureholders”) to restructure the Debentures as follows:
$50.0 million 7.50% Series A convertible debentures due on January 31, 2016
(the “Series A Debentures”)
- The Company will exchange the entire principal amount of the Series A Debentures, on the basis of a price of $0.0361 per share, for approximately 1.385 billion common shares issued from treasury representing approximately 48.9% of the pro forma common shares outstanding on the closing of the Transaction which is expected to be on or before January 31, 2016 (the “Closing Date”).
- Provided the Transaction is approved, the Company will pay, on the Closing Date, $1.875 million in cash to the Series A Debentureholders which represents the interest that would be accrued and unpaid on the Series A Debentures on January 31, 2016.
- If the Transaction is not approved, the Company will, pursuant to and in accordance with the terms of the indenture (as supplemented) governing the Debentures (the “Indenture”), exercise its right to pay both the principal and accrued and unpaid interest on the Series A Debentures in common shares on the maturity date of January 31, 2016.
- Prior to December 22, 2015, the Company intends to send a separate maturity notice to the Series A Debentureholders notifying them of its intention to exercise the common share repayment right on maturity if the Transaction is not approved.
$46.0 million 7.25% Series B convertible debentures due on June 30, 2017
(the “Series B Debentures”)
- The Company will exchange the entire principal amount of the Series B Debentures, on the basis of a price of $0.0361 per share, for approximately 1.274 billion common shares issued from treasury representing approximately 45.0% of the pro forma common shares outstanding on the Closing Date.
- Provided the Transaction is approved, the Company will pay, on the Closing Date, $1.667 million in cash to the Series B Debentureholders which represents the interest that would be accrued and unpaid on the Series B Debentures at the first possible redemption date of June 30, 2016. The Series B Debentureholders will receive this final interest payment five months earlier than it would otherwise be due.
- Approval of the Transaction will not affect the Series B Debentures interest payment of $1.667 million due on December 31, 2015. The Company intends to make this interest payment in cash.
- If the Transaction is not approved, Anderson intends to, pursuant to and in accordance with the terms of the Indenture:
- redeem the Series B Debentures one year early, at the first possible redemption date of June 30, 2016; and
- exercise its right to pay both the principal and accrued and unpaid interest on the Series B Debentures in common shares on the redemption date of June 30, 2016.
The rules of the Toronto Stock Exchange (the “TSX”) require the exchange price to be at market. The price of $0.0361 per common share underlying the proposed Transaction represents the volume weighted average trading price (“VWAP”) on the TSX for the 5 trading days ended November 6, 2015 (the last trading prior to the announcement of the proposed Transaction), in accordance with the TSX definition. If the Transaction is not approved, the Debentures will be repaid or redeemed, as applicable, pursuant to and in accordance with the terms of the Indenture.
Background to the proposal
The Series A Debentures in the principal amount of $50.0 million mature on January 31, 2016 and the Series B Debentures in the principal amount of $46.0 million mature on June 30, 2017. On or after June 30, 2016 and prior to the maturity date, the Series B Debentures are redeemable, at the option of the Company.
The dramatic decrease in commodity prices has impacted the Company’s options with respect to payment of these Debentures when they become due.
The Company will not have sufficient funds to settle the Debentures in cash upon their maturity.
The Company has the option to settle all or a portion of the outstanding Debentures at maturity or redemption through the issuance of common shares by giving notice of such intent to Debentureholders not more than 60 and not less than 40 days prior to the applicable maturity or redemption date.
The current economic environment remains very challenging in terms of low commodity prices, the uncertainty related to economic and environmental policy changes that may result from new provincial and federal governments in Canada, the uncertainty related to the magnitude and duration of the TCPL restrictions of natural gas volume receipts in Alberta that is impacting production from both gas and oil wells, geopolitical risks and challenging economic conditions throughout the world.
In August 2015, the Company completed the previously announced sale of certain shallow gas assets for net proceeds of approximately $3.0 million. While the Company is currently undrawn on its bank line, the amount of the available bank line was established in May 2015 with better commodity prices than we are seeing today. The Company’s next review of its bank lines is scheduled for May 2016 and with today’s commodity prices and outlook, the available bank lines could be reduced. Cash on hand and available bank lines will be needed to continue to develop the Company’s Cardium light oil base.
The Board hired Cormark Securities Inc. (“Cormark”) in March 2015 to act as its exclusive financial advisor to assess the Company’s options with respect to the convertible debentures. Anderson and Cormark have thoroughly investigated and exhausted a variety of financial and strategic alternatives, including the sale of the Company, production royalty structures and alternative financing vehicles, as well as extensions or other amendments to the terms of the existing Debentures. As part of that process, a data room with confidential data was opened generating a significant amount of interest in Anderson from a broad group of counterparties. However, with the complexity of Anderson’s capital structure and the challenging conditions in both commodity pricing and capital markets discussed above, the process failed to generate any acceptable proposals. The complexity of Anderson’s capital structure was also identified as a concern in Anderson’ strategic alternatives process in 2012 and 2013.
Anderson’s Board has determined that the Transaction is in the best interests of the Company and its stakeholders given, among other considerations, that it will eliminate Anderson’s overall debt of $96.0 million, simplify its capital structure, provide for a more orderly issuance of common shares to Debentureholders relative to the alternatives and provide considerable improvement in Anderson’s financial liquidity. The determination to approve the Transaction was made based on a range of factors, including a verbal opinion received by the Board from Cormark that the consideration to be received by the Debentureholders pursuant to the Transaction, if implemented, is fair, from a financial point of view, to the Debentureholders and current shareholders of the Company. A written fairness opinion from Cormark, addressed to the Board will be included in the information circular to be circulated to Debentureholders in connection with the Transaction.
Advantages of the proposal
Management and the Board of Directors of Anderson (the “Board”) believe that the Transaction is in the best interests of all stakeholders, and provides a number of benefits, including the following.
The Transaction would eliminate Anderson’s overall debt of $96.0 million, and thereby reduce the financial risk for the Company in a difficult economic and commodity price environment. The Transaction would simplify the capital structure of the Company, and the pro forma interest burden would be reduced by $7.1 million from 2015 levels, which would result in increased cash flow available to actively invest into Anderson’s high quality asset base and enhance Anderson’s net asset value.
The Transaction would remove the uncertainty surrounding the settlement of the Debentures in the future, and position the Company to attract future capital, retain staff, and ultimately create more investor interest in the Company.
The Transaction would allow Debentureholders to receive full face value recognition for their Debentures in common shares of the Company, even though the Debentures are trading at a substantial discount in the market, and would provide cash, not common shares, to Debentureholders for the final interest payments.
The Transaction would provide certainty with respect to the dilution resulting from the conversion of the Debentures into common shares.
Pro forma total net debt to annualized funds from operations, and common share interests
The following table sets forth Anderson’s pro forma total net debt to annualized funds from operations as at September 30, 2015, assuming the completion of the Transaction:
|(thousands of dollars)
|September 30, 2015||Pro Forma
September 30, 2015
|Adjusted working capital(1)||$||7,533||$||8,992||(4)|
|Convertible debentures – liability component||(93,300||)||–||(5)|
|Total net debt(1)||$||(85,767||)||$||8,992|
|Cash from operating activities (for the 3 months ended September 30, 2015)||1,334||$||3,209||(6)|
|Change in non-cash working capital||(583||)||(687||)(7)|
|Funds from operations(1)(for the 3 months ended September 30, 2015)||832||$||2,603|
|Annualizing factor||x 4||x 4|
|Annualized funds from operations(2)||$||3,328||$||10,412|
|Ratio(3)||26 to 1||nil|
(1) Adjusted working capital, total net debt and funds from operations are considered additional GAAP measures. Refer to the section entitled “Additional GAAP Measures” in the MD&A for a more complete description of these additional GAAP measures.
(2) Annualized funds from operations is determined as the quarterly funds from operations multiplied by a factor of 4 to represent an estimated full year of funds from operations based on that particular quarter’s funds from operations.
(3) This ratio reflects total debt to annualized funds from operations and is calculated as a ratio of total net debt over annualized funds from operations.
(4) Adjusted working capital has been increased by the accrued interest on the Debentures of $1.459 million in accounts payable to calculate the pro forma September 30, 2015 balance as though no Debentures were outstanding during the period.
(5) Convertible debentures – liability component has been reduced to nil to calculate the pro forma September 30, 2015 balance as though no Debentures were outstanding during the period.
(6) Cash from operating activities for the three months ended September 30, 2015 has been increased by $1.875 million of interest paid on the Debentures over the period to calculate the pro forma cash flow from operating activities as though no Debentures were outstanding during the period.
(7) Change in non-cash working capital has been decreased by $0.104 million for the change in accrued interest in accounts payable over the period to calculate the pro forma amount.
The following table sets forth the pro forma common share interests as of September 30, 2015, assuming the completion of the Transaction:
|(thousands of shares)
|Number of Shares||Percentage|
|Common shares outstanding at September 30, 2015||172,550||6.1%|
|Series A Debentureholder shares issued as part of Transaction||1,385,042||48.9%|
|Series B Debentureholder shares issued as part of Transaction||1,274,238||45.0%|
|Common shares outstanding after completion of the Transaction||2,831,830||100.0%|
Key Steps in the Transaction
Anderson expects to hold a meeting of the Debentureholders to consider the Transaction in January 2016. Pursuant to the Indenture, an extraordinary resolution approving the Transaction is required to be passed at a meeting of Debentureholders in which the holders of not less than 25% of the principal value of each series of Debentures outstanding are present in person or by proxy. The resolution must be passed by 66 2/3% of the votes for each series of Debentures and for all the Debentures in total. If a quorum is not achieved at the initial meeting, the meeting will be adjourned to a date approximately 14 days later. At the adjourned meeting, Debentureholders present in person or by proxy shall constitute a quorum. Votes submitted by proxy for the initial meeting shall remain valid for the adjourned meeting, unless withdrawn by the Debentureholder.
The Transaction will not require any action by shareholders and is not subject to any shareholder vote.
The Transaction is subject to approval by the Toronto Stock Exchange.
If the proposal is not approved by the Debentureholders, the Company intends to exercise its rights to pay both the principal and accrued and unpaid interest on the Debentures in common shares on their maturity date or, in the case of the Series B convertible debentures, the first available redemption date of June 30, 2016, pursuant to the terms of the Indenture.
Further information about the Transaction and the meeting of Debentureholders will be provided in an information circular expected to be distributed to Debentureholders in the coming weeks.
In summary, the Company has made significant progress since completion of the strategic alternatives process in the fourth quarter of 2013. The Company has grown oil, condensate and NGL production and reserves through development of its Cardium assets. Oil, condensate and NGL made up 45% of total BOED production in the third quarter of 2015 compared to 26% in the fourth quarter of 2013 (net of properties sold), when the Company emerged from the strategic alternatives process. Cardium production growth in the Willesden Green area was 81% for oil and 137% on a BOE basis from January 2014 to January 2015. Cardium proved plus probable (“P&P”) reserves made up 73% of total reserves volumes on a BOE basis at the end of 2014, compared to 60% at the end of 2013. The 2014 Cardium program delivered excellent results with a P&P recycle ratio of 2.0, a finding, development and acquisition cost on a P&P basis of $21.47 per BOE (including changes in future development costs, but excluding technical revisions and economic factors) and a capital efficiency ratio of $28,600 per BOED. The Company continued to have stellar drilling results, outpacing the average performance of industry competitors in the Willesden Green field in terms of lower capital costs and higher IP 30 rates. The reorganization completed in January 2015 provided additional non-dilutive liquidity for the Company. Anderson’s reaction to the oil price collapse was to terminate its capital program early, to not incur bank debt and to leave cash in the bank for the future. Anderson has also taken significant strides to reduce head office costs, field operating costs and to bring down capital costs.
With the approval of the proposed Transaction, the Company would be debt free and would be able to restart its Cardium drilling program. With stronger commodity prices, we feel the Company may then be able to attract investor interest.
I appreciate the support of the Board of Directors and the financial sacrifices that staff and management have had to make to reposition the Company for the future. The Company’s most recent investor presentation will be posted on the Company’s website at www.andersonenergy.ca.
Thank you for your continued patience.
Brian H. Dau, President & Chief Executive Officer
Certain statements in this news release including, without limitation, management’s business strategy and assessment of future plans and operations; benefits and valuation of the development prospects described herein; number of locations in drilling inventory; drilling program success; timing and location of drilling and tie-in of wells and the costs thereof; timing of construction of facilities; timing of shut-in and abandonment of wells and impact thereof; productive capacity of the wells; expected production rates and risks to such expectations; improved production from slick water fracture technology; percentage of production from oil, condensate and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; reserves and net present value of future net revenue from reserves; ability to attain cost savings and amount thereof; tax horizon; expectations related to future operating netbacks; programs to optimize, rationalize, consolidate and improve profitability of assets; including the impact from shutting-in or abandonment of wells; the sale of various shallow gas assets and the impact on production; factors on which the continued development of the Company’s oil and gas assets are dependent; the impact of the TCPL outages on past and future production; benefits of recently completed transactions including the result on the Company’s liquidity; benefits of the Transaction and the impact of the Transaction on Anderson and its capital structure, financial position, liquidity and net asset value, including that the Transaction will create a financially stronger company and better allow for the pursuit of its business and operational goals; growth potential of Anderson’s asset base; the results of the annual review of Anderson’s bank facility; Anderson’s common share interests assuming the completion of the Transaction; Anderson’s ability to implement its plans relating to the Transaction; anticipated dates and information relating to the Debentureholder meeting and the closing of the Transaction; Anderson’s intentions if the Transaction is not approved; commodity price outlook; and general economic outlook may constitute “forward-looking information” within the meaning of applicable securities laws and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets; volatility of commodity prices; currency fluctuations; imprecision of reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities; wells not performing as expected; incorrect assessment of the value of acquisitions and farm-ins; failure to realize the anticipated benefits of acquisitions and farm-ins; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; availability of third-party transportation and processing facilities; ability to access sufficient capital from internal and external sources; ability of Anderson’s common shares to remain listed on the TSX; the receipt, in a timely manner, of regulatory and Debentureholder approval in respect of the Transaction; the plans of Debentureholders and other counterparties related to the Transaction; the expected costs of the Transaction; and other factors, many of which are beyond the Company’s control. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management’s future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at Anderson’s website (www.andersonenergy.ca).
The forward-looking statements contained in this news release are made as at the date of this news release and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
CONVERSION MEASURES AND SHORT-TERM PRODUCTION RATES
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 six Mcf to one 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.
This news release contains production information obtained from reports prepared by certain third parties. None of the authors of such reports has provided any form of consultation, advice or counsel regarding any aspect of this news release and the Company does not warrant the accuracy or completeness of the third party information. Industry data is subject to variations and cannot be verified due to limits on the availability and reliability of data inputs, the voluntary nature of the data gathering process and other limitations and uncertainties inherent in any market or other survey.
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 or reserves. Individual well performance may vary.
|bbl – barrel
bpd – barrels per day
BOE – barrels of oil equivalent
BOED – barrels of oil equivalent per day
m3 – cubic meters
Mbbls – thousand barrels
MBOE – thousand barrels of oil equivalent
Mstb – thousand stock tank barrels
NGL – natural gas liquids, excluding condensate
WTI – West Texas Intermediate
|AECO – intra-Alberta Nova inventory transfer price
Bcf – billion cubic feet
Btu – British thermal unit
GJ – gigajoule
Mcf – thousand cubic feet
Mcfd – thousand cubic feet per day
MMBtu – million British thermal units
MMcf – million cubic feet
scf – standard cubic foot
US – United States
Anderson Energy Inc.