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EQU > SEC Filings for EQU > Form 10-K on 15-Mar-2013All Recent SEC Filings

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Form 10-K for EQUAL ENERGY LTD.


15-Mar-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

This report, and in particular this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of this Annual Report on Form 10-K regarding the identification of and risks relating to forward-looking statements, as well as

Part I, Item 1A "Risk Factors" in this Annual Report on Form 10-K.

The following discussion of our financial condition and results of operations should be read in conjunction with the "Financial Statements and Supplementary Data" as set out in Part II, Item 8 of this Annual Report on Form 10-K.

CORPORATE PROFILE

Equal Energy Ltd. is an exploration and production oil and gas company which had its head office in Calgary, Alberta for 2012 which has subsequently moved to Oklahoma City, Oklahoma during 2013. Equal's shares are listed on the New York Stock Exchange (EQU) and Equal's shares and convertible debentures are listed on the Toronto Stock Exchange (EQU and EQU.DB.B). Its current production is approximately 6,400 boe per day (49% NGLs, 49% natural gas and 2% crude oil) all of which is produced in Oklahoma.

On May 3, 2012, the Company's board of directors initiated a strategic review process to identify, examine and consider alternatives with the view to enhancing shareholder value. As a result of the strategic review process, several important initiatives were concluded:

- A major reduction in debt as a result of several asset sales.

- Initiation of a USD$0.20 per share annual dividend starting January 1, 2013, which is to be paid quarterly.

- A review of the composition of the board of directors and senior management team.

- A review of compensation policies.

- A focus on the liquids-rich natural gas Hunton property in Central Oklahoma.

As a result of the Canadian asset sales in Q4 2012, the Canadian operations are considered discontinued for 2012 and all comparative years in the following Management's Discussion and Analysis ("MD&A"), financial statements and notes to the financial statements. Only the Company's continuing operations, which include the Oklahoma operations and corporate costs, are discussed in the following MD&A except in the Discontinued Operations section where the Canadian operations are discussed and referred to.

It is important to note that within this MD&A, production volumes reflect the Company's continuing operations net of royalty interest which is in accordance with U.S. regulations. Reported production volumes in previous press releases, quarterly reports, annual reports and other public documents included discontinued Canadian operations and were in accordance with the Canadian National Instrument 51 - 101 which is before the deduction of royalty interest.

                                                          Year ended December 31
   Financial and Operations
            Summary
   (in thousands except for
 volumes, percentages and per
    share and boe amounts)          2012          Change           2011          Change            2010
FINANCIAL
Oil, NGL and natural gas
revenues
including realized hedging           67,541             (7 %)       72,887             32 %       55,327
Funds from operations (1)            30,048            (12 %)       34,113             71 %       19,915
Net income/(loss) from
continuing operations                31,111       >1000%                 2           (100 %)       3,615
 Per share - basic (2) ($)             0.89       >1000%              0.00           (100 %)        0.14
 Per share - diluted (2) ($)           0.82       >1000%              0.00           (100 %)        0.14
Net income/(loss) from
discontinued operations              30,716            472 %         5,371           (141 %)     (12,957 )
 Per share - basic (2) ($)             0.87            412 %          0.17           (133 %)       (0.52 )
 Per share - diluted (2) ($)           0.76            375 %          0.16           (131 %)       (0.52 )
Net income/(loss)                    61,827       >1000%             5,373           (158 %)      (9,342 )
 Per share - basic (2) ($)             1.76            935 %          0.17           (145 %)       (0.38 )
 Per share - diluted (2) ($)           1.58            888 %          0.16           (142 %)       (0.38 )
Total assets                        226,222                        323,094                       247,228
Working capital (deficiency)
including
long-term debt (1)                   26,602                       (131,462 )                     (26,697 )
Convertible debentures               45,000                         45,000                       119,775
Shareholders' equity                161,277                         99,880                        37,329
SHARES OUTSTANDING
Shares outstanding - basic(2)
(000s)                               35,062                         32,040                        24,595
Shares outstanding - diluted(2)
(000s)                               41,125                         32,768                        24,896
Shares outstanding at period
end (000s)                           35,227                         34,779                        27,710
OPERATIONS
Average daily production net of
royalties(3)
 NGL (bbls per day)                   3,237             35 %         2,401             32 %        1,813
 Natural gas (mcf per day)           22,664             30 %        17,461             46 %       11,954
 Oil (bbls per day)                     172            (19 %)          212             (5 %)         224
 Total (boe per day)                  7,186             30 %         5,523             37 %        4,030
Average sales price (4)
 NGL ($ per bbl)                      31.41            (34 %)        47.46             14 %        41.73
 Gas ($ per mcf)                       2.95            (23 %)         3.83            (21 %)        4.87
 Oil ($ per bbl)                      92.63              4 %         89.22             13 %        78.72
Cash flow netback (1) ($ per
boe)
 Revenue (4)                          25.68            (29 %)        36.16             (4 %)       37.61
 Production expenses                   7.78             (7 %)         8.39             18 %         7.11
 Production taxes                      1.43            (13 %)         1.64             (8 %)        1.79
 Operating netback                    16.47            (37 %)        26.13             (9 %)       28.71
 Cash general and
administrative                         2.88            (31 %)         4.20            (56 %)        9.62
 Interest expense                      2.25            (54 %)         4.88            (27 %)        6.68
 Other cash costs (5)                 (0.08 )         (162 %)         0.13           (111 %)       (1.14 )
 Cash flow netback                    11.42            (33 %)        16.92             25 %        13.54

(1) Funds from operations, cash flow netback and working capital including long-term debt are non-GAAP financial measures. Please refer to "Non-GAAP Financial Measures".

(2) Weighted average shares outstanding. See Note 9 to the Financial Statements.

(3) Production volumes reflect the Company's continuing operations net of royalty interest which is in accordance with U.S. regulations. Reported production volumes in previous press releases, quarterly reports, annual reports and other public documents included discontinued Canadian operations and were in accordance with the Canadian National Instrument 51 - 101 which is before the deduction of royalty interest.

(4) Price received includes royalty deductions, realized commodity contract gains or losses and excludes unrealized mark-to-market gain or loss.

(5) Other cash costs include realized foreign exchange gains and losses.


QUARTERLY FINANCIAL INFORMATION (in thousands of Canadian dollars except for per

share amounts)

                        Full Year                           2012                            Full Year                           2011
                          2012               Q4           Q3           Q2           Q1            2011           Q4           Q3           Q2           Q1
Revenues                    64,393       14,960       11,793       19,034       18,606          78,311       18,727       27,018       23,393        9,173
Funds from
operations                  30,048        7,770        6,293        6,248        9,737          34,113       10,787       10,838        8,218        4,270

Income/(loss) before
taxes from
continuing
operations                  37,945       (1,245 )     34,873          290        4,027          10,834        5,036        1,959        9,239       (5,400 )
Net income/(loss)
from continuing
operations                  31,111       (5,153 )     38,615       (5,429 )      3,078               2           92       (1,885 )      8,007       (6,212 )
Net income/(loss)
from discontinued
operations                  30,716       28,057        3,346       (1,566 )        879           5,371       (1,192 )        810        1,131        4,622
Net income/(loss)           61,827       22,904       41,961       (6,995 )      3,957           5,373       (1,100 )     (1,075 )      9,138       (1,590 )

Basic net income/(loss) per share ($):
Continuing
operations                    0.89        (0.15 )       1.10        (0.16 )       0.09            0.00         0.00        (0.05 )       0.26        (0.22 )
Discontinued
operations                    0.87         0.80         0.10        (0.04 )       0.02            0.17        (0.03 )       0.02         0.04         0.16
Net income/(loss)             1.76         0.65         1.20        (0.20 )       0.11            0.17        (0.03 )      (0.03 )       0.30        (0.06 )

Diluted net income/(loss) per share ($ per share):
Continuing
operations                    0.82        (0.15 )       0.94        (0.16 )       0.09            0.00         0.00        (0.05 )       0.22        (0.22 )
Discontinued
operations                    0.76         0.68         0.08        (0.04 )       0.02            0.16        (0.03 )       0.02         0.04         0.14
 Net income/(loss)            1.58         0.57         1.03        (0.20 )       0.11            0.16        (0.03 )      (0.03 )       0.26        (0.06 )

For 2012, quarterly revenues and funds from operations were generally lower than the previous quarters mainly due to the asset disposition in Q4 2011 and decreased prices received for NGLs and natural gas. The Company's sale of its assets in Northern Oklahoma in Q3 2012 resulted in a gain of $36.0 million which increased net income. The Company's sale of its assets in Canada in Q4 2012 resulted in a gain of $56.8 million which increased net income during the quarter and resulted in the discontinuation of operations in Canada.

Q4, Q3 and Q2 2011 revenues and funds from operations are higher than the previous quarters due to the June 1, 2011 acquisition of working interests from a former joint venture partner in Oklahoma (the "Hunton Acquisition"). During Q1 2011, funds from operations were lower due to legal fees relating to legal proceedings against a former joint venture partner in Oklahoma.

OVERALL PERFORMANCE

Average production for 2012 of 7,186 boe per day was 30% higher than the 2011 production of 5,523 boe per day mainly due to the Hunton Acquisition which occurred in June 2011 contributing for the full year in 2012 and contribution from new wells drilled during 2012 which was partially offset by the sale of the Northern Oklahoma assets on September 24, 2012, that produced approximately 1,100 boe per day, and the natural decline in older production.

Revenues including realized hedging decreased 7% to $67.5 million from $72.9 million in 2011 due to decreased NGL and natural gas prices. The decreases in prices were partially offset by increased NGL and natural gas production and realized gains on commodity contracts. The average price received for NGLs decreased 34% to $31.41 per bbl compared to $47.46 per bbl in 2011 due to excess supply relative to demand in the mid-continent of the United States where Equal's NGL production is located. The average price received for natural gas in 2012, net of commodity contract settlements, decreased 23% to $2.95 per mcf from $3.83 per mcf in 2011 due to an oversupply situation for North American natural gas. The average price received for oil in 2012 increased 4% to $92.63 per bbl from $89.22 per bbl in 2011.

Production expense increased 21% to $20.5 million from $16.9 million in 2011 mainly due to increased volumes from the Hunton Acquisition in June 2011 and the addition of new wells drilled during the past year. On a per boe basis, production expense decreased 7% to $7.78 per boe in 2012 from $8.39 per boe in 2011 partially due to the sale of the Northern Oklahoma assets that had a higher average production expense per boe than the Company's average production costs and a Company focus on cost control. Production taxes increased 13% to $3.8 million from $3.3 million in 2011 mainly due to the 30% increase in production which was partially offset by the decrease in prices received for NGLs and natural gas.

General and administrative costs ("G&A") decreased 11% to $7.6 million from $8.5 million in 2011. The decrease in G&A costs was mainly due to higher costs in 2011 for legal fees related to court proceedings involving a former joint venture participant that ended during Q2 2011. Interest expense was $5.9 million which was 40% lower than $9.8 million in 2011. The lower interest expense is mainly due to proceeds from the asset dispositions being used to pay down the bank credit facility and lower interest paid on the convertible debentures as an 8.25% debenture was redeemed in Q4 2011.

The overall result was that funds from operations decreased by 12% to $30.0 million in 2012 compared to $34.1 million in 2011 due to the decrease in revenues and increase in production expense which were partially offset by decreases in G&A and interest expense.

In 2012, the Company had net income of $61.8 million which was mainly due to the $36.0 million ($22.3 million net of income tax) gain on sale of assets in Oklahoma and the $58.8 million ($42.6 million net of income tax) gain on sale of assets in Canada.

PRODUCTION VOLUMES

Production Net of Royalties
                                                         Year ended December 31
                                    2012          Change          2011          Change          2010
Daily sales volumes net of
royalties(1) - average
NGL (bbls per day)                    3,237             35 %        2,401             32 %        1,813
Natural gas (mcf per day)            22,664             30 %       17,461             46 %       11,954
Oil (bbls per day)                      172            (19 %)         212             (5 %)         224
Total (boe per day)                   7,186             30 %        5,523             37 %        4,030

Sales volumes mix by product
NGL                                      45 %                          43 %                          45 %
Natural gas                              53 %                          53 %                          49 %
Oil                                       2 %                           4 %                           6 %
                                        100 %                         100 %                         100 %

(1) Production volumes reflect the Company's continuing operations net of royalty interest which is in accordance with U.S. regulations. Reported production volumes in previous press releases, quarterly reports, annual reports and other public documents included discontinued Canadian operations and were in accordance with the Canadian National Instrument 51 - 101 which is before the deduction of royalty interest.

In 2012, production of 7,186 boe per day was 30% higher compared to 5,523 boe per day during 2011. The increase in production is primarily due to the Hunton Acquisition which occurred in June 2011 contributing to the full year in 2012 and volumes from new wells drilled during 2012 which was partially offset by the sale of the Northern Oklahoma assets in September 2012 that produced approximately 1,100 boe per day and the natural production decline.

In 2011, production of 5,523 boe per day was 37% higher compared to 4,030 boe per day during 2010. The increase in production is primarily due to the Hunton Acquisition which occurred in June 2011, wells drilled during 2011 and a reactivation and workover program.

On September 24, 2012, Equal closed the sale of its interest in its Northern Oklahoma assets for total cash consideration of US$40.0 million to its Mississippian joint venture partner Atlas Resource Partners L.P. ("Atlas"). The assets sold include production of approximately 1,100 boe per day which is primarily natural gas and NGLs, related infrastructure and interests in approximately 8,550 acres of Mississippian lands.

The Company's current portfolio of assets consists almost exclusively of the liquids-rich natural gas asset in Central Oklahoma. Equal's current corporate production is approximately 6,400 boe per day consisting of 49% natural gas, 49% NGLs and 2% crude oil.

For the year ended December 31, 2012, Equal drilled 9 (7.2 net) wells with a 100% success rate:

3 (2.7 net) Twin Cities / Central Dolomite Hunton liquids-rich natural gas wells in Central Oklahoma;

4 (3.5 net) K-9 Hunton vertical liquids-rich natural gas wells in Northern Oklahoma which were sold in Q3 2012; and

2 (1.0 net) K-9 Mississippian horizontal oil wells which were sold in Q3 2012.

COMMODITY PRICING

Pricing Benchmarks
                                                         Year ended December 31
                                    2012          Change          2011          Change          2010
Propane, Conway, KS (US$ per
bbl)                                  36.12            (37 %)       56.89             20 %        47.24
NYMEX natural gas (US$ per
mmbtu)                                 2.79            (32 %)        4.08             (8 %)        4.42
NYMEX natural gas (US$ per mcf)
(1)                                    2.89            (32 %)        4.22             (8 %)        4.57
WTI (US$ per bbl)                     94.19             (1 %)       95.12             20 %        79.53
Average exchange rate: US$ to
Cdn$1.00                               1.00             (1 %)        1.01              4 %         0.97
WTI (Cdn$ per bbl)                    94.19              0 %        94.17             15 %        81.92

(1) Conversion rate of 1.0350 mmbtu per mcf.

The prices Equal receives for its NGLs are indexed to Conway, Kansas prices, so the price variations at Conway are reflected in Equal's variations in NGL price. The propane price quoted at Conway, Kansas has historically been a representative proxy of the price Equal receives for its basket of NGL products produced in Oklahoma. The NYMEX natural gas price is based at Henry Hub in Louisiana and is priced in U.S. dollars per mmbtu. West Texas Intermediate ("WTI") is a standard benchmark for the price of oil and is expressed in U.S. dollars per barrel. For the purposes of financial reporting, Equal expresses its realized prices for oil, NGLs and natural gas in Canadian dollars.

Benchmark propane prices for 2012 decreased 37% to an average of US$36.12 per bbl from US$56.89 per bbl in 2011 due to an increased supply in the market from increased liquids-rich drilling and lower consumption from a warmer than usual winter. Benchmark propane prices for 2011 increased 20% to an average of US$56.89 per bbl from US$47.24 per bbl compared to the same period in 2010 which was also partially offset in Canadian dollar terms, by the strengthening of the Canadian dollar compared to the U.S. dollar.

Benchmark natural gas prices for 2012 on the NYMEX decreased 32% to an average of US$2.79 per mmbtu from US$4.08 per mmbtu in 2011. Benchmark natural gas prices for 2011 on the NYMEX decreased 8% to an average of US$4.08 per mmbtu from US$4.42 per mmbtu compared 2010.

Benchmark oil prices for 2012 decreased slightly by 1% to an average of US$94.19 per bbl WTI from US$95.12 per bbl WTI in 2011. Benchmark oil prices for the 2011 increased 20% to an average of US$95.12 per bbl WTI from US$79.53 per bbl WTI in 2010.

Average Commodity Prices
Received
                                                         Year ended December 31
                                    2012          Change          2011          Change          2010
NGL (Cdn$ per bbl)                    31.41            (34 %)       47.46             14 %        41.73
Natural gas (Cdn$ per mcf)             2.22            (36 %)        3.46            (12 %)        3.93
Natural gas commodity contract
settlements (Cdn$ per mcf)             0.73             96 %         0.37            (61 %)        0.94
Combined natural gas (Cdn$ per
mcf)                                   2.95            (23 %)        3.83            (21 %)        4.87
Oil (Cdn$ per bbl)                    92.63              4 %        89.22             13 %        78.72
Total (1) (Cdn$ per boe)              25.68            (29 %)       36.16             (4 %)       37.62

(1) Price received excludes unrealized mark-to-market gain or loss on commodity contracts.

In 2012, the average price received for NGLs decreased 34% to $31.41 per bbl compared to $47.46 per bbl in 2011 due to excess supply relative to demand in the mid-continent of the United States where Equal's NGL production is located. The average price received for natural gas in 2012, net of commodity contract settlements, decreased 23% to $2.95 per mcf from $3.83 per mcf in 2011 due to an oversupply situation in North America resulting in a decrease in market prices for natural gas. The average price received for oil in 2012 increased 4% to $92.63 per bbl from $89.22 per bbl in 2011.

In 2011, the average price received for NGLs increased 14% to $47.46 per bbl compared to $41.73 per bbl in 2010. The average price received for natural gas in 2011, net of commodity contract settlements, decreased 21% to $3.83 per mcf from $4.87 per mcf in 2010 due to an oversupply situation resulting in a decrease in market prices for natural gas. The average price received for oil in 2011 increased 13% to $89.22 per bbl from $78.72 per bbl in 2010.

REVENUES

Revenues (in thousands of
Canadian dollars)
                                                         Year ended December 31
                                    2012          Change          2011          Change          2010
NGL revenues                         37,202            (11 %)      41,593             51 %       27,620
Natural gas revenues                 18,433            (16 %)      22,024             28 %       17,154
Oil revenues                          5,843            (15 %)       6,895              7 %        6,432
Realized gain on commodity
contracts                             6,063            155 %        2,375            (42 %)       4,121
Revenues including realized
hedging                              67,541             (7 %)      72,887             32 %       55,327
Unrealized gain/(loss) on
commodity contracts                  (3,148 )         (158 %)       5,424           (695 %)        (912 )
Total revenues                       64,393            (18 %)      78,311             44 %       54,415

In 2012, revenues including realized hedging decreased 7% to $67.5 million from $72.9 million in 2011 due to decreased NGL and natural gas prices. The decreases in prices were partially offset by increased NGL and natural gas production and realized gains on commodity contracts.

NGL revenues for 2012 decreased 11% to $37.2 million from $41.6 million in 2011 which was the result of a 34% decrease in sales price received for NGLs partially offset by a 35% increase in production volumes. Natural gas revenues for 2012 decreased 16% to $18.4 million from $22.0 million in 2011 which was the result of a 36% decrease in sales price received for natural gas partially offset by a 30% increase in production volumes. Oil revenues for 2012 decreased 15% to $5.8 million compared to $6.9 million in 2011 which was the result of a 19% decrease in production volumes partially offset by a 4% increase in price received. In 2012, there was a realized gain on commodity contracts of $6.1 million compared to a $2.4 million realized gain in 2011 and an unrealized loss of $3.1 million compared to an unrealized gain of $5.4 million in 2011.

In 2011, revenues including realized hedging increased 32% to $72.9 million from $55.3 million in 2010 due to increased NGL and natural gas volumes produced from the Hunton Acquisition in June 2011.

NGL revenues for 2011 increased 51% to $41.6 million from $27.6 million in 2010 which was the result of a 32% increase in production volumes and a 14% increase in sales price received for NGLs. Natural gas revenues for 2011 increased 28% to $22.0 million from $17.2 million in 2010 which was the result of a 46% increase in production volumes partially offset by a 12% decrease in sales price received for natural gas. Oil revenues for 2011 increased 7% to $6.9 million compared to $6.4 million in 2010 which was the result of a 13% increase in sales price received partially offset by a 5% decrease production volume. In 2011, there was a realized gain on commodity contracts of $2.4 million compared to a $4.1 million realized gain in 2010 and an unrealized gain of $5.4 million compared to an unrealized loss of $0.9 million in 2010.

The Company's 2013 assumptions for planning purposes are: US$90.00 per bbl for WTI (Equal realization of 96% of WTI), US$3.90 per mmbtu for NYMEX natural gas (Equal realization of 87% of NYMEX), US$0.90 per gallon (US$37.80 per bbl) for Conway propane (Equal realization of 89% of Conway Propane). The Company constantly monitors actual prices against plan prices and adjusts its operational plans to address changes in cash flow caused by commodity price fluctuation.

COMMODITY CONTRACTS

The Company has a risk management policy which is in line with the terms of its bank credit facility that permits management to use specified price risk management strategies for up to 65% of its estimated net oil and gas production which includes fixed price contracts, costless collars and the purchase of floor price options and other derivative instruments to reduce the impact of price volatility and ensure minimum prices for a maximum of 36 months. The program is designed to provide price protection on a portion of Equal's future production in the event of adverse commodity price movement, while retaining exposure to upside price movements. By doing this, Equal seeks to provide a measure of stability and predictability of cash inflows to enable it to carry out its planned capital spending programs.

The mark-to-market value of the commodity contracts is determined based on the estimated fair value as at December 31, 2012 that was obtained from the counterparties to the economic hedges. Equal then evaluates the reasonableness of the valuations in comparison to the value of other commodity contracts it currently owns as well as recently quoted prices received from other counterparties for various commodity contracts. The Company deals with large, credit-worthy financial institutions to diversify its counterparty risk. The credit worthiness of each counterparty is assessed at the time of purchase of each financial instrument and is regularly assessed based on any new information regarding the counterparty.

At December 31, 2012, Equal had the following financial derivatives and fixed price contracts outstanding:

Derivative   Commodity   Price (2)     Volume per     Period
Instrument                              day (2)
. . .
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