MANAGEMENT’S DISCUSSION AND ANALYSIS
The following management’s discussion and analysis (“MD&A”) should be read in conjunction with Novus Energy Inc.’s (“Novus” or the “Company”) audited consolidated financial statements as at and for the year ended December 31, 2010. The accompanying consolidated financial statements of Novus have been prepared by management and approved by the Company’s Audit Committee. The financial data presented herein has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Additional information relating to Novus, including the Company’s Annual Information Form, is available on SEDAR at www.sedar.com and Novus’s website (www.novusenergy.ca).
The Company changed its fiscal year end from September 30 to December 31 effective October 1, 2008. As a result, while the Company’s current fiscal year is the twelve month period ending December 31, 2010, the comparative fiscal year is the fifteen month period ending December 31, 2009.
On August 5, 2009, the Company consolidated its common shares on the basis of one new common share for every ten common shares outstanding. All share and per share, warrant and per warrant and option and per option amounts prior to August 5, 2009 have been retroactively adjusted to reflect the share consolidation.
All tabular amounts are stated in thousands except per share amounts or as otherwise stated. This MD&A is current as at April 13, 2011.
NON-GAAP FINANCIAL MEASUREMENTS
Included in the MD&A are references to certain financial measures commonly used in the oil and gas industry, such as funds flow from (used in) operations and operating netbacks. These measures have no standardized meanings, are not defined by Canadian GAAP, and accordingly are referred to as non-GAAP measures. These supplemental measures are used by management to assess operating results between periods and between peer companies as they provide an indication of the results generated by the Company’s principal business activities before the consideration of how these activities are financed or how the results are taxed.
Novus determines funds flow from (used in) operations as cash provided by (used in) operating activities prior to changes in non-cash working capital items and asset retirement expenditures. A reconciliation of cash provided by (used in) operating activities to funds flow from (used in) operations is presented below:
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Cash provided by (used
in) operating activities $ 4,134 $ (576) $ 2,967 $ (3,550)
Changes in non-cash
working capital items (1,694) (296) 756 (284)
Asset retirement
expenditures 4 43 32 308
Funds flow from (used
in) operations $ 2,444 $ (829) $ 3,755 $ (3,526)
OTHER MEASUREMENTS
The reporting and measurement currency of this MD&A is the Canadian dollar.
Reported production represents Novus’ ownership share of sales before the deduction of royalties. Where amounts are expressed on a barrel of oil equivalent (“boe”) basis, natural gas has been converted at a ratio of six thousand cubic feet to one boe. This ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boe’s may be misleading, particularly if used in isolation. References to natural gas liquids (“liquids”) include condensate, propane, butane and ethane, and one barrel of liquids is considered to be equivalent to one boe. ADVISORY REGARDING FORWARD-LOOKING STATEMENTS
Certain disclosures set forth in this MD&A constitute forward-looking statements. Any statements contained herein that are not statements of historical facts may be deemed to be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “anticipate”, “believes”, “budget”, “continue”, “could”, “estimate”, “forecast”, “intends”, “may”, “plan”, “predicts”, “projects”, should”, “will” and other similar expressions. All estimates and statements that describe the Company’s future, goals, or objectives, including management’s assessment of future plans and operations, may constitute forward-looking information under securities laws. Forward-looking statements involve known and unknown risks and uncertainties which include, but are not limited to: exploration, development and production risks; assessments of acquisitions; reserve measurements; availability of drilling equipment; access restrictions; permits and licenses; aboriginal claims; title defects; commodity prices; commodity markets, transportation and marketing of crude oil, liquids and natural gas; reliance on operators and key personnel; competition; corporate matters; funding requirements; access to credit and capital markets; market volatility; cost inflation; foreign exchanges rates; general economic and industry conditions; environmental risks; Kyoto protocol; and government regulation and taxation.
Forward-looking statements relate to future events and/or performance and although considered reasonable by Novus at the time of preparation, may prove to be incorrect and actual results may differ materially from those anticipated in the statements made. Novus does not undertake any obligation to publicly update forward-looking information except as required by applicable securities law.
THE COMPANY
Novus is engaged in the acquisition, exploration, development and production of petroleum and natural gas reserves in Western Canada.
The principal and head office of the Company is located at Suite 1200, 520 - 5th Avenue S.W., Calgary, Alberta T2P 3R7. The registered office of the Company is located at 3500, 855 – 2nd Street S.W., Calgary, Alberta T2P 4J8.
Novus’ common shares are listed and posted for trading on the TSX Venture Exchange under the symbol NVS.
RESULTS OF OPERATIONS Production
Three months ended Fiscal year ended
Average production Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Oil & liquids (bbls/d) 989 92 597 83
Natural gas (mcf/d) 3,490 1,405 3,107 1,447
Oil equivalent (boe/d) 1,571 327 1,115 324
Production during the fourth quarter of 2010 was 17% higher than the 1,339 boe/d recorded in the third quarter of 2010. The biggest reason for the increase was having a full three months of production from wells that were completed and tied-in part way through the third quarter.
Revenue and pricing
Gross production revenue for the three months ended December 31, 2010 and 2009 was $7.98 million and $1.16 million respectively. For the year ended December 31, 2010, production revenue was $20.21 million versus $4.96 million for the fiscal year ended December 31, 2009. The increase in revenue is due to the increased production described above as well as a significant recovery in oil prices.
The Company did not enter into any commodity derivative contracts locking in petroleum or natural gas prices during the three or twelve months ended December 31, 2010 nor has it entered into any such contracts as of the date of this MD&A.
Three months ended Fiscal year ended
Sales revenue Dec 31, 2010 Dec 31,2009 Dec 31, 2010 Dec 31, 2009
Oil & liquids $ 6,783 $ 506 $ 15,604 $ 1,902
Natural gas 1,196 650 4,605 3,060
Total $ 7,979 $ 1,156 $ 20,209 $ 4,962
Three months ended Fiscal year ended
Sales price per unit Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Oil & liquids ($/bbl) 74.53 59.52 71.59 49.99
Natural gas ($/mcf) 3.73 5.03 4.06 4.63
Blended ($/boe) 55.21 38.47 49.66 33.47
Royalties
Royalties, which include crown, freehold and overriding royalties paid on oil, liquids and natural gas production, amounted to $1.02 million during the last quarter of 2010 compared to $196 thousand during the corresponding quarter in 2009. For the year ended December 31, 2010, total royalties were $3.52 million compared to $837 thousand for the 2009 fiscal year. The increase in the 2010 figures stems from the increased production and revenue over the comparative periods. Expressed as a percentage of revenue, royalties decreased in the last quarter of 2010 due to increased production from the Company’s Saskatchewan producing properties, which generally carry a lower royalty rate. The increase in boe costs are attributable to higher sales prices on the Company’s volumes, which translates into higher unit costs.
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Total $ 1,021 $ 196 $ 3,518 $ 837
Total (per boe) $ 7.06 $ 6.54 $ 8.65 $ 5.65
% of revenue 13% 17% 17% 17%
Operating costs
Total operating costs for the quarter ended December 31, 2010 amounted to $2.36 million ($16.31/boe) compared to $622 thousand ($20.72/boe) for the quarter ended December 31, 2009. For the year ended December 31, 2010, operating costs were $6.47 million ($15.89/boe) compared to $2.83 million ($19.09/boe) for the fiscal year ended December 31, 2009. When comparing these figures, operating decreased on a per unit basis due higher production volumes coming from the Company’s greater Dodsland area, which has a lower operating cost environment than some of the Company’s other producing areas. The Company anticipates that operating costs will continue to decline on a per unit basis as production from the greater Dodsland area offsets the Company’s more expensive Alberta natural gas properties. The $16.31/boe figure for the most recent quarter was an increase from the $15.15/boe recorded in the three month period ending September 30, 2010 due largely to the expense of three workovers and start-up costs associated with wells brought on production in December, 2010.
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31,2009 Dec 31, 2010 Dec 31, 2009
Operating costs $ 2,357 $ 622 $ 6,468 $ 2,830
$/boe 16.31 20.72 15.89 19.09
Transportation costs
Total transportation costs for the three months ended December 31, 2010 amounted to $280 thousand ($1.94/boe) compared to $48 thousand ($1.61/boe) during the quarter ended December 31, 2009. For the year ended December 31, 2010, transportation costs were $650 thousand ($1.60/boe) compared to $193 thousand ($1.30/boe) for the fiscal year ended December 31, 2009. The increase in the fourth quarter of 2010 reflects a change in the marketing of the Company’s oil production, where increased transportation costs are more than offset by higher effective product prices.
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31,2009 Dec 31, 2010 Dec 31, 2009
Transportation $ 280 $ 48 $ 650 $ 193
$/boe 1.94 1.61 1.60 1.30
Operating netbacks
The following table summarizes the Company’s operating netbacks. Operating netbacks are non-GAAP measures and are used by Novus to measure the profitability of crude oil and natural gas sales, subsequent to the deduction of royalty, operating and transportation costs. This measure is not necessarily comparable to operating netbacks as reported by other entities.
Three months ended Fiscal year ended
Netback per boe Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31,2009
Revenue $ 55.21 $ 38.47 $ 49.66 $ 33.47
Royalties (7.06) $ (6.54) (8.65) $ (5.65)
Operating costs (16.31) (20.72) (15.89) (19.09)
Transportation (1.94) (1.61) (1.60) (1.30)
Operating netbacks $ 29.90 $ 9.60 $ 23.52 $ 7.43
General and administrative expenses
Total general and administrative expenses were $1.79 million ($12.36/boe) for the last quarter of 2010, versus $1.11 million ($37.08/boe) in the corresponding quarter of 2009. For the year ended December 31, 2010, general and administrative expenditures were $5.35 million ($13.15/boe) compared to $4.52 million ($30.50/boe) for the fiscal year ended December 31, 2009.
General and administrative expenditures increased in 2010 as additional staffing requirements were needed to support the Company’s current growth phase. Furthermore, the Company assumed additional commitments regarding office space as a result of its corporate acquisitions in late 2009 and early 2010. The Company believes that while general and administrative expenditures may grow on an absolute basis, they will continue to decrease on a per boe basis as new production is added and comes on stream.
Transaction costs
Transactions costs of $237 thousand were incurred in the first half of 2010, resulting from the three business combinations in March and April, 2010. New accounting standards pertaining to business combinations require acquisition costs to be expensed, rather than capitalized as they were previously. The Company adopted these standards in advance of the transition to International Financial Reporting Standards (“IFRS”) as they substantially align with IFRS.
Interest expense
There was no interest expense in 2010 as the Company paid off its bank debt in March, 2009. Interest expense was $90 thousand for the fiscal year ended December 31, 2009. Going forward, the Company anticipates drawing on it credit facilities to fund its 2011 capital program. This will result in interest charges being incurred, with the amount of such charges dependent on the timing of payment for these expenditures, as well as the effective interest rate charged by the Company’s lender.
Stock-based compensation
The Company accounts for stock-based compensation using the fair-value method. Under this method, compensation expense is recorded over the vesting terms of the options. During the fourth quarter of 2010, $1.14 million of stock-based compensation expense was recognized, compared to $250 thousand recognized during the last quarter of 2009. For the year ended December 31, 2010, $3.08 million of stock-based compensation expense was recognized, versus $465 thousand for the fiscal year ended December 31, 2009. The increase stems from the granting and vesting of additional stock options in 2010.
No compensation expense has been recorded for the performance warrants as management does not expect the performance warrants to vest based on current Net Asset Value per share projections.
Depletion and depreciation
Total depletion and depreciation expense for the three months ended December 31, 2010 and 2009 amounted to $5.65 million ($39.12/boe) and $1.12 million ($37.27/boe) respectively. For the fiscal years ending December 31, 2010 and 2009, the charges were $15.9 million ($39.06/boe) and $4.83 million ($32.60/boe), respectively. The $7 million impairment provision on March 31, 2009 was excluded for the purposes of the December 31, 2009 comparative calculation and the higher charges in 2010 largely reflect the increased cost of the Company’s assets along with higher rates of production.
Accretion
Income taxes
Current income taxes were for the quarters ended December 31, 2010 and 2009 were $91 thousand and $nil respectively. For the fiscal years ended December 31, 2010 and 2009, current income taxes were $230 thousand and $17 thousand respectively. The taxes are the result of the Saskatchewan Resource Surcharge on the Company’s Saskatchewan production revenue, including adjustments based on predecessor company filings.
The future income taxes recovery for the year ended December 31, 2010 was $12.5 million. In light of the Company’s positive funds flow from operation in the last half of 2010 and continuing plans for 2011, Novus reassessed the likelihood of the Company being able to utilize its tax pools. As a result of the reassessment, the Company is recognizing a future tax income tax asset of $16.66 million, resulting in a 2010 future income tax recovery of $12.5 million. The future income tax asset does not represent the full value of income tax assets, which will again be reassessed as the Company moves through 2011 and gains more certainty regarding future funds flow.
During the period ended December 31, 2010, the Company settled a transfer pricing audit with the Canada Revenue Agency (“CRA”). As a result of the settlement, CRA waived all proposed cash penalties. The settlement had no impact on the financial results of the Company.
The following is a summary of the estimated tax pools of the Company as at December 31, 2010:
Classification Dec 31, 2010
Non-capital loss carry-forwards $ 54,863
Canadian development expenditures 41,527
Canadian oil and gas property expenditures 37,721
Canadian exploration expenditures 20,525
Scientific research and development 18,899
Capital cost allowance 18,899
Share issue costs 4,557
Other 252
$ 197,243
Non-capital loss carry-forwards available to reduce future year’s income for tax purposes expire as follows:
Year Amount
2011 $ 709
2013 4,672
2014 1,898
2022 – 2030 47,584
Total non-capital loss carry-forwards $ 54,863
Net income (loss), funds flow and cash flow from (used in) operations
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Net income (loss) $ 7,279 $ (2,233) $ (3,084) $ (15,957)
per share - basic & diluted 0.04 (0.04) (0.02) (0.45)
Funds flow from (used in)
operations (1) 2,444 (829) 3,755 (3,526)
per share - basic & diluted 0.01 (0.01) 0.02 (0.10)
Cash flow from (used in)
operations 4,134 (576) 2,967 (3,550)
per share - basic & diluted 0.02 (0.01) 0.02 (0.10)
Weighted average shares - basic 166,395 60,687 153,847 35,374
(1) Funds flow from (used in) operations has been presented for information purposes only and should not be considered an alternative to, or more meaningful than, cash flow from (used in) operating activities as determined in accordance with GAAP. The Company considers funds flow from (used in) operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to repay debt and to fund future growth through capital investment. The determination of Novus’ funds flow from (used in) operations may not be comparable to the same reported by other companies. The reconciliation of cash flow from (used in) operations to funds flow from (used in) operations can be found in the “Non-GAAP financial measurements” section at the front of this MD&A. Funds flow from (used in) operations per share was calculated using the same weighted average shares outstanding used in calculating net income (loss) per share.
Capital expenditures
During the fourth quarter of 2010, the Company recorded $18.61 million of cash capital expenditures compared to $10.03 million during the fourth quarter of 2009. For the year ended December 31, 2010, net cash capital expenditures were $55.2 million versus $11.91 million in the fiscal year ended December 31, 2009. In 2010, the Company participated in the drilling and completion of 50 wells (42.6 net), of which 43 (37.6 net) were horizontal wells in the greater Dodsland area. The Company also completed the construction of two oil batteries in the greater Dodsland area. This compares to 7 wells (4.5 net) and no facilities in fiscal 2009. A further breakdown of the capital expenditures is outlined below:
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Land acquisition /
retention $ 999 $ 6 $ 5,639 $ 202
Geological, geophysical
and seismic 3 540 372 923
Drilling and completions 14,148 2,521 38,001 3,180
Drilling royalty credits (104) (250) (587) (250)
Facilities, equipping and
tie-ins 3,429 600 8,135 1,244
Property acquisitions, net 199 6,573 3,460 6,550
Other corporate assets (65) 43 181 72
Cash expenditures $ 18,609 $ 10,033 $ 55,201 $ 11,921
The Company also had non-cash capital expenditures as follows:
Three months ended Fiscal year ended
Dec 31, 2010 Dec 31, 2009 Dec 31, 2010 Dec 31, 2009
Land acquisition/farm-in $ 697 $ - $ 1,970 $ -
Property acquisitions - 799 - 799
Business combinations - 15,735 11,178 15,735
Non-cash expenditures $ 697 $ 16,534 $ 13,148 $ 16,534
Land acquisition/ farm-in
On February 9, 2010, the Company issued 325,000 common shares at an ascribed value of $0.88 per common share in exchange for the right to farm-in on certain lands in the greater Dodsland area. The Company has met the terms of the agreement and earned its interests in the lands.
Business combinations
PrivateCo.
On March 1, 2010, the Company acquired all of the issued and outstanding common shares of a private oil and gas company (“PrivateCo”), which had approximately 214 barrels of oil equivalent per day of production, 25.5 net sections of undeveloped lands and working capital of approximately $8 million at the time of acquisition. As consideration, the Company issued 18,666,211 common shares at an ascribed value of $0.91 per common share. The ascribed value was equal to the closing price of the Company's shares on the TSX Venture Exchange on March 1, 2010.
Of the lands acquired, 40% are located within the greater Dodsland area. The production volumes are primarily natural gas and require only minor increases to ongoing administrative costs.
Coyote Resources Ltd.
On March 4, 2010, the Company acquired all of the issued and outstanding common shares of Coyote, which owned two sections of prospective land within the greater Dodsland area. As consideration, the Company paid $702 thousand and assumed $222 thousand of debt.
Titan Oilfield Services Inc.
On April 7, 2010, the Company acquired all of the issued and outstanding common shares of Titan, which owned 2.3 sections of prospective land within the greater Dodsland area. As consideration, the Company paid $1.25 million.
Key amongst all the business combinations was the acquisition of undeveloped lands in the Company’s core operational area of Dodsland, Saskatchewan.
LIQUIDITY AND CAPITAL RESOURCES Capital structure
The Company considers its capital structure to consist of working capital, including bank debt. The Company manages its capital structure in order to meet its financial obligations and sustain the future development of the Company. The Company’s Officers are responsible for managing the Company’s capital and do so through quarterly meetings and regular reviews of financial information including budgets and forecasts. The Company’s Directors are responsible for overseeing this process. Methods used by the Company to manage its capital include the issuance of new share capital to raise additional funds and adjusting its capital spending to manage current and projected debt levels. The Company continually monitors business conditions including: changes in economic conditions; the risk of its drilling programs; forecasted commodity prices; and potential corporate or asset acquisitions.
From April, 2009, when the current management team was appointed, through to November, 2010, the Company monitored its capital structure to ensure that it maintained a positive working capital position free of bank debt. In December, 2010 the Company was able to increase its revolving operating demand loan from $5 million to $22 million and this, combined with the ability to generate positive funds flow from operations, has enabled the Company to change its approach to managing its capital structure.
Three months ended Dec 31, 2010
Current assets $ 10,750
Current liabilities (12,590)
Net debt (1,840)
Cash flow from operations $ 4,134
Changes in non-cash working capital items (1,694)
Asset retirement expenditures 4
Funds flow from operations 2,444
Annualized funds flow from operations 9,776
Net debt to annualized funds flow from operations 0.2:1
The Company’s share capital is not subject to any external restrictions; however its credit facility is subject to periodic reviews. The credit facility also contains certain covenants such that the Company cannot, without prior approval of the bank, hedge or contract petroleum or natural gas volumes, on a fixed price basis, exceeding 50% of production volumes, nor can it monetize or settle any fixed price financial hedge or contract. The credit facility also contains a financial covenant that requires the Company to maintain a working capital ratio of at least 1:1, but for the purposes of the covenant, bank debt and the fair value of any commodity contracts are excluded and the unused portion of the credit facility may be added to current assets. As at December 31, 2010, this working capital ratio was 2.6:1.
Equity instruments
During the year ended December 31, 2010, the Company issued 22,730,000 common shares pursuant to an equity financing; 18,666,211 common shares pursuant to the acquisition of PrivateCo; 325,000 common shares pursuant to a farm-in agreement; 1,806,849 common shares pursuant to asset purchase agreements; and 1,454,000 common shares on the exercise of share purchase warrants. The Company also repurchased 125,000 common shares pursuant to its normal course issuer bid (“NCIB”).
On May 18, 2010, the Company completed an equity offering whereby the Company issued 22,730,000 common shares at a price of $1.10 per common share for aggregate gross proceeds of $25 million ($23.47 million net). The Company used the net proceeds of the Offering for the development and expansion of its core areas and general corporate purposes.
The 1,454,000 common shares issued on the exercise of share purchase warrants resulted in gross proceeds of $1.09 million realized by the Company.
The Company instituted a NCIB bid for the period September 13, 2010 to September 12, 2011, pursuant to which a maximum of 5,000,000 common shares may be acquired during the period. The cost of the 125,000 common shares acquired and cancelled by the Company was $112 thousand.
As at December 31, 2010, the Company had the following equity instruments outstanding:
Common shares outstanding 166,961
Issuable upon the exercise of outstanding share purchase warrants 26,276
Issuable upon the exercise of outstanding stock options 15,375
Issuable upon the exercise of outstanding performance warrants 4,200
The following table summarizes the outstanding share purchase warrants as at December 31, 2010:
The following table summarizes the outstanding stock options as at December 31, 2010:
The Company’s 4,200,000 performance warrants were granted on September 4, 2009 for a term of three years. Each performance warrant is exercisable into one common share at a price of $0.56 per performance warrant upon the Company achieving certain targets in growth in net assets value per fully diluted share outstanding (“NAV per share”). With reference to the initial NAV per share calculated as $1.10, 1/3 of the performance warrants shall vest upon an increase in NAV per share of 25%, 2/3 of the performance warrants shall vest upon an increase in NAV per share of 33 1/3%, and all of the performance warrants shall vest upon an increase in NAV per share of 50%. The performance warrants will also vest upon a change of control of the Company. As of December 31, 2010, none of the performance warrants have vested.
Subsequent to December 31, 2010, 2,881,400 common shares were issued on the exercise of the warrants; 72,500 common shares were issued on the exercise of stock options; and 165,000 shares were acquired and cancelled under the NCIB.
As of the date of this MD&A, Novus has 169,749,812 common shares outstanding. A further 23,394,600 common shares are reserved for issuance pursuant to the exercise of outstanding shares purchase warrants; 15,362,000 common shares are reserved for issuance pursuant to the exercise of outstanding stock options; and 4,200,000 common shares are reserved for issuance pursuant to the exercise of outstanding performance warrants.
Working capital and bank debt
At December 31, 2010, the Company had a working capital deficit of $1.84 million compared to positive working capital of $19.44 million at December 31, 2009. Components of the working capital figures are contained in the following table:
Dec 31, 2010 Dec 31, 2009
Cash and cash equivalents $ 5,063 $ 22,143
Accounts receivable 5,134 2,512
Deposits and prepaid expenses 553 457
Accounts payable and accrued liabilities (12,590) (5,674)
Total working capital $ (1,840) $ 19,438
As at December 31, 2010, the Company had no bank debt outstanding. The Company has available a $22 million revolving operating demand loan and a $6 million acquisition/development demand loan. The loans are available to the Company by way of prime rate based loans, bankers’ acceptance and letters of credit/guarantee with interest paid monthly. Interest rates are determined quarterly and are based on a grid
Date of Issue Number of Warrants Exercise Price Date of Expiry
Mar 31, 2009 26,276 $ 0.75 Mar 31, 2012
Date of Grant Number of Options Exercise Price Date of Expiry
system which, for the revolving operating demand loan range from prime plus 0.75% to prime plus 2.5% depending on the debt to cash flow ratio. Interest rates on the acquisition/development are charged at an additional 0.5%. The credit facilities are secured by a general assignment of book debts and a $75 million debenture with a floating charge over all assets of the Company with a negative pledge and undertaking to provide fixed charges upon request. The credit facility is subject to a financial covenant that requires the Company to maintain a working capital ratio of at least 1:1, but for the purposes of the covenant, bank debt and the fair value of any commodity contracts are excluded and the unused portion of the revolving operating demand loan may be added to current assets. As at December 31, 2010, this ratio was 2.6:1. COMMITMENTS
As at December 31, 2010, the Company had commitments as follows:
2011 Thereafter
Office Lease $ 414 $ -
SELECTED ANNUAL INFORMATION
Fiscal year ended
Dec 31, 2010 Dec 31, 2009 Sep 30, 2008
Production revenue $ 20,209 $ 4,962 $ 4,924
Net income (loss) (3,084) (15,957) (3,086)
per share - basic & diluted (0.02) (0.45) (0.43)
Funds flow from (used in) operations 3,755 (3,526) (44)
per share - basic & diluted 0.02 (0.10) (0.01)
Total assets 133,706 80,636 31,716
Total long-term liabilities 5,193 2,385 951
In March, 2009, the Company was recapitalized. A new management team was appointed, the Board of Directors reconfigured, and a financing of $13.88 million was completed. In August, 2009, the Company changed its name from Regal Energy Ltd to Novus Energy Inc and consolidated its common shares on the basis of one new common share for every ten common shares outstanding. Additional financings of $30 million and $25 million were completed in December, 2009 and May, 2010 respectively. The Company used the proceeds from these financings to fund its capital programs, resulting in the increase in production revenue and turnaround of funds flow in 2010. Increased depletion charges were a large part of the increased loss in 2009, while a $12.5 million future income tax recovery helped reduce the loss in 2010. SUMMARY OF QUARTERLY RESULTS
Three months ended
Dec 31, 2010 Sep 30, 2010 Jun 30, 2010 Mar 31, 2010 Production revenue $ 7,979 $ 6,155 $ 3,088 $ 2,987
Funds flow from (used in) operations 2,444 2,076 (686) (79)
per share – basic & diluted 0.01 0.01 - -
Net income (loss) 7,279 (3,419) (4,120) (2,824)
per share – basic & diluted 0.04 (0.02) (0.03) (0.02)
Cash capital expenditures, net 18,609 10,499 20,155 5,938
Average daily production (boe/d) 1,571 1,339 774 710
Average selling price ($/boe) 55.21 49.95 43.81 46.76
Operating Netback ($/boe) 29.90 26.18 10.21 20.46
Weighted average shares – basic 166,395 166,373 153,288 128,781
Three months ended
Dec 31, 2009 Sep 30, 2009 Jun 30, 2009 Mar 31, 2009 Production revenue $ 1,156 $ 839 $ 804 $ 911
Funds flow from (used in) operations (829) (559) (476) (1,379)
per share – basic & diluted (0.01) (0.01) (0.01) (0.09)
Net income (loss) (2,233) (1,800) (1,415) (9,147)
per share – basic & diluted (0.04) (0.04) (0.03) (0.60)
Cash capital expenditures, net 10,034 (40) 329 220
Average daily production (boe/d) 327 345 327 306
Average selling price ($/boe) 38.47 26.45 29.96 33.05
Operating Netback ($/boe) 9.60 3.02 7.88 2.24
Weighted average shares – basic 60,687 42,755 42,755 15,313
Weighted average shares – diluted 60,687 42,755 42,755 15,313
Production in the second and third calendar quarters of 2009 rose as previous operational and cold weather issues at Eight Mile, Kaybob, and Garrington, became resolved. Production for the last quarter of 2009 was adversely impacted by shut-in oil production at Cardiff and Wembley as well as severe cold weather curtailing gas production during December. Volumes increased in the first quarter of 2010 due to wells drilled in the previous quarter coming on stream, three full months of production resulting from the December 2009 business combination with Ammonite Energy Ltd., (“Ammonite”) and one month of production from the March 2010 business combinations. Increases for the second quarter of 2010 were due to new production from wells drilled in the first and second quarters of 2010 and a full quarter of production from the 2010 business combinations. Increases for the third and fourth quarters of 2010 were due to the production from the new wells drilled, completed, and placed onstream in an ongoing fashion. Production revenue is a function of sales volumes and commodity prices, so while volumes didn’t fluctuate significantly in 2009, declining commodity prices negatively impacted production revenue. The turnaround in prices over the last quarter of 2009 helped boost that period’s sale figures, in spite of the reduced volumes. While oil prices continued their recovery in 2010, gas prices slowly declined. Most of the Company’s added volumes in the third and fourth quarters of 2010 were from oil, which improved the revenue figure.
Funds flow from (used in) operations starts with production revenue and is affected by royalties, operating and transportation costs, general and administrative expenditures, interest expenses, transaction costs and current taxes. For 2009, funds flow used in operations was impacted by severance costs associated with the change of management in March and year-end administrative costs in December. In the first quarter of 2010, increased production volumes, coupled with higher commodity prices and greater operational efficiencies, resulted in improved funds flow figures. A combination of lower commodity prices, higher royalties, and increased operating costs adversely affected flow funds in the second quarter, but the third quarter funds flow figure improved dramatically due to the increased revenue, and this continued on through the fourth quarter.
The net loss for the three months ended March 31, 2009 included higher funds flow used in operations and a $7 million ceiling test write-down. Net loss increased through the last half of 2009 and into 2010 due largely to higher non-cash items, such as depletion charges and stock-based compensation costs.
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company’s financial instruments as at December 31, 2010 consist of cash and cash equivalents, accounts receivable, deposits, and accounts payable and accrued liabilities. The fair value of these instruments approximates their carrying value due to their short-term nature.
The following table presents the Company’s fair value hierarchy for those assets and liabilities measured at fair value as of December 31, 2010.
Level 1 Level 2 Level 3 Total
Cash and cash equivalents $ 5,063 $ - $ - $ 5,063
Total $ 5,063 $ - $ - $ 5,063
The nature of the Company’s financial instruments and operations expose the Company to certain risks. The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework, and senior management employs various strategies to ensure that the exposure to risk is in compliance with the Company’s business objectives and tolerance levels.
Credit Risk
Credit risk is the risk of financial loss to the Company if a counter party to a financial instrument fails to meet its contractual obligation. The Company is exposed to credit risk with respect to accounts receivable and cash and cash equivalents.
Substantially all of the Company’s accounts receivable are with customers and joint interest partners in the oil and gas industry and are subject to normal industry credit risks. The Company markets its petroleum and natural gas to several marketers so that the exposure to any one entity is minimized. Receivables from oil and natural gas marketers are normally collected on the 25th day of the month following production. One of these marketers owed the Company $2.1 million at December 31, 2010, which was subsequently received. Receivables from joint venture partners are typically collected within one to three months of the joint venture billing being issued, however collection is dependent on industry factors such as commodity price fluctuations, escalating costs, the risk of unsuccessful drilling, and disputes amongst partners. The Company attempts to mitigate credit risk from joint venture partners by obtaining partner approval of significant capital costs prior to expenditure. While the Company does not typically obtain collateral from joint venture partners, it may cash call a partner in advance of the work being done. In addition, the Company has the ability to withhold production from partners in the event of non-payment. Should any of the Company’s customers or partners be unable to settle amounts due, the impact on the Company could be significant. The maximum exposure to losses arising from accounts receivable and cash and cash equivalents is equal to their total carrying amounts on the balance sheet. As at December 31, 2010, the Company had a provision for doubtful accounts in the amount of $175 thousand (2009 - $200 thousand). Although an allowance has been provided, the Company will continue to pursue collection of the balance. The allowance may be adjusted if circumstances or events change. When determining whether past due accounts are collectible, the Company factors in the past credit history of the counter parties.
As at December 31, 2010, the Company’s accounts receivable were comprised of the following:
Sales revenue receivable $ 3,244
Joint interest receivable 1,290
Cash call receivable 93
Accrued and other receivable 507
As at December 31, 2010, the Company estimates its accounts receivables to be aged as follows:
The Company considers all amounts greater than 90 days as past due and collectible.
Cash and cash equivalents consist of bank balances. The Company manages the credit exposure of cash by selecting financial institutions with high credit ratings.
Liquidity risk
This is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s objective in managing liquidity risk is to ensure that it has sufficient resources available to meet its liabilities when due. The Company’s ongoing liquidity is impacted by various external events and conditions, including commodity price fluctuations and the global economic downturn. At December 31, 2010, the Company’s accounts payable and accrued liabilities were $12.59 million all of which are due for payment within normal terms of trade, which are generally between 30 and 60 days. As at December 31, 2010, the Company has cash on hand of $5.06 million and a $22 million revolving operating demand loan to manage its liquidity and settlement of liabilities.
The Company’s financial liabilities at December 31, 2010 are aged as follows: Total accounts payable
and accrued liabilities 0 to 30 days 31 to 60 days 61 to 90 days Greater than 90 days
$ 12,590 $ 10,468 $ 1,616 $ 68 $ 438
The Company expects to satisfy its obligations under accounts payable and accrued liabilities within the next year. As well, the Company is required to meet certain financial commitments as described in the Liquidity and Capital Resources as well as the Commitments sections of this MD&A.
Foreign currency exchange risk
This is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although the Company’s petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada are impacted by changes in the exchange rate between the Canadian and United States dollar and the impact of such exchange rate fluctuations cannot be accurately quantified. The Company had no forward exchange rate contracts in place, nor any working capital items denominated in foreign currencies, as at or during the year ended December 31, 2010.
Commodity price risk
This is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are not only impacted by the relationship between the Canadian and United States dollar as outlined above, but also by world economic events that dictate the levels of supply and demand. The Company had no commodity contracts locking in petroleum or natural gas prices as at or during the year ended December 31, 2010.
Interest rate risk
This is the risk that the fair value or future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. From time to time, the Company may attempt to mitigate this risk by utilizing short-term bankers’
Total accounts
receivable 0 to 30 days 31 to 60 days 61 to 90 days Greater than 90 days
acceptances to lock in a portion of its bank debt at fixed rates. No interest rate swaps or financial contracts were in place as at or during the year ended December 31, 2010.
Operational risks
Novus’ operational activities are focused on the Western Canadian Sedimentary Basin, a competitive environment with a number of companies exploring for hydrocarbons. Other operational risks include weather delays, mechanical or technical difficulties, and exploration risks associated with finding economically viable hydrocarbon reserves. Novus attempts to manage these risks by maintaining an inventory of certain critical equipment; conducting advance planning to manage its drilling programs in an efficient and cost effective manner; and hiring experienced technical staff and personnel to conduct its exploration programs.
Novus’ field operations are also subject to health, safety and environmental risks. The Company maintains a Health, Safety and Environmental Policy and an Emergency Response Plan which are updated bi-annually or as needed to comply with current legislation. Both are designed to protect the health and safety of all concerned persons in addition to respecting any environmental regulations. Novus also maintains insurance covering property, drilling, pollution, and commercial general liability.
Financial Risks
Financial risks faced by the Company include fluctuations in commodity prices, US/Canadian foreign exchange rates, interest rates, the ability to access capital and/or debt markets, and credit risks associated with its joint venture partners and purchasers. At times, Novus may hedge a portion of its production, or lock in foreign exchange or interest rates. It also attempts to mitigate overall financial risks by maintaining a positive working capital position; having a flexible capital program; and managing its reliance on joint venture partners.
Regulatory Risks
Novus is subject to various policies and legislation governing the oil and gas industry. Although these policies are out of Novus’ direct control, the Company is a member of the Small Explorers and Producers Association of Canada, which, amongst other things, represent the interests of junior oil and gas companies to the public, governments, and other sectors of the energy industry in Canada. Novus operates in a manner that is in compliance with applicable regulations and industry standards and must react to comply with changes as they occur.
CHANGES IN ACCOUNTING POLICIES AND NEW ACCOUNTING PRONOUNCEMENTS Adoption of new accounting policies
a) Business combinations
b) Consolidated financial statements
In January 2009, the AcSB issued CICA Handbook Section 1601, “Consolidations” and 1602, “Non-controlling Interests”. Section 1601 carries forward the requirements of Section 1600, “Consolidated Financial Statements”, other than those relating to non-controlling interests which would be covered in Section 1602. These standards are effective for annual and interim periods beginning on or after January 1, 2011 with earlier adoption permitted. The Company has elected to adopt the standards effective January 1, 2010, and they did not have an impact on the Company’s consolidated financial statements.
Accounting pronouncements
a) International Financial Reporting Standards (“IFRS”)
In January 2006, the CICA’s AcSB adopted a strategic plan for the direction of accounting standards in Canada. In February 2008, the AcSB confirmed the changeover from Canadian GAAP to IFRS will be required for publicly accountable enterprises effective for fiscal years beginning on or after January 1, 2011. In July 2009, the International Accounting Standards Board adopted certain amendments and exemptions to IFRS 1 including standards relating to the transition to IFRS for resource based companies. The amendment will permit the Company to apply IFRS prospectively by utilizing its current reserves at the transition date to allocate the Company’s full cost pool, with the provision that a ceiling test, under IFRS standards, be conducted at the transition date. The Company will adopt this exemption.
The Company has finalized its IFRS accounting policy decisions and is in the process preparing its January 1, 2010 restated IFRS opening balance sheet. A high level review of the major differences between Canadian GAAP and IFRS has been done. The audit committee has approved the Company’s IFRS policy selections that have been presented by management as disclosed herein. At this time, Novus has identified the following key differences as being applicable:
i) Exploration and Evaluation (“E&E”) expenditures
Upon transition to IFRS, the Company will reclassify E&E expenditures that are included in property and equipment on the balance sheet at January 1, 2010. E&E expenditures consist of the book value of undeveloped land and seismic data that relate to exploration properties. E & E assets are classified according to the nature of the expenditures and technical feasibility and commercial viability of extracting oil and gas from a property that has not been established as containing proved reserves. E&E assets have the option to be depleted and must be assessed for impairment when indicators suggest the possibility of impairment exists. Costs will be reclassified to property and equipment, to the extent they are not impaired, when proved and/or probable reserves have been assigned to the property. Upon transition to IFRS, the Company estimates $4.9 million of property and equipment will be reclassified on the balance sheet to E&E assets. ii) Depletion expense
Depletion of property and equipment will be based on significant components. Depletion of resource properties will be based on field cost centre levels rather than on one full cost level under Canadian GAAP. The Company has the option to base its depletion calculation on either proved reserves or proved plus probable reserves and has elected to use proved plus probable reserves.
iii) Impairment
determined that the impairment has decreased or no longer exists. Upon transition to IFRS, it is anticipated that most, if not all, of the $5.9 million of goodwill will be impaired and charged to the deficit account.
iv) Asset retirement obligations
Novus’ asset retirement obligations are likely to increase under IFRS as a result of the change from a credit-adjusted risk-free rate used to discount cash flows, to a risk-free rate. In addition, any change in the discount rate will affect the entire obligation, not just the current additions as it does now under Canadian GAAP. Upon transition to IFRS, the Company estimates an increase in asset retirement obligations in the range of $1-2 million, with a corresponding amount charged to the deficit account.
v) Share capital
Under Canadian GAAP, the gross proceeds on flow-through shares are recorded as share capital. When the flow-through expenditures are renounced, share capital is reduced by the estimated future taxes payable as a result of the renouncement. Under IFRS, share capital on flow-through shares is recorded at the estimated fair value of non flow-through shares, with the difference between the gross proceeds and fair value recorded as a liability. When the flow-through expenditures are renounced, the future tax liability is recorded through a charge to income tax expense less the liability previously recorded. Upon transition to IFRS, the Company estimates an increase in share capital in the range of $2-3 million, with a corresponding amount charged to the deficit account.
