EXHIBIT 99.3
MANAGEMENT’S DISCUSSION AND ANALYSIS
This management’s discussion and analysis (“MD&A”) of ARC Resources Ltd. (“ARC” or the “Company”) is Management’s analysis of the financial performance and significant trends or external factors that may affect future performance. It is dated February 10, 2016 and should be read in conjunction with the audited consolidated financial statements as at and for the year ended December 31, 2015 (the "financial statements"), and the MD&A and unaudited condensed interim consolidated financial statements for the periods ended March 31, 2015, June 30, 2015 and September 30, 2015 as well as ARC’s Annual Information Form that is filed on SEDAR at www.sedar.com. All financial information is reported in Canadian dollars and all per share information is based on diluted weighted average shares, unless otherwise noted.
This MD&A contains additional generally accepted accounting principles ("GAAP") measures, non-GAAP measures and forward-looking statements. Readers are cautioned that the MD&A should be read in conjunction with ARC’s disclosure under the headings “Non-GAAP Measures,” “Additional GAAP Measures,” “Forward-looking Information and Statements” and "Glossary" included at the end of this MD&A.
ABOUT ARC RESOURCES LTD.
ARC is a dividend-paying Canadian oil and gas company headquartered in Calgary, Alberta. ARC’s activities relate to the exploration, development and production of conventional oil and natural gas in Canada with an emphasis on the development of properties with a large volume of hydrocarbons in place commonly referred to as “resource plays.”
ARC’s vision is to be a leading energy producer, focused on delivering results through its strategy of risk-managed value creation. ARC is committed to providing superior long-term financial returns for its shareholders, creating a culture where respect for the individual is paramount and action and passion are rewarded. ARC runs its business in a manner that protects the safety of employees, communities and the environment. ARC’s vision is realized through the four pillars of its strategy:
1. | High quality, long-life assets – ARC’s unique suite of assets includes both Montney and other assets. ARC’s Montney assets consist of world-class resource play properties, concentrated in the Montney geological formation in northeast British Columbia and northern Alberta. The Montney assets provide substantial growth opportunities, which ARC will pursue to create value through long-term profitable development. Other assets are located in Alberta and Saskatchewan and include core assets in the Cardium formation in the Pembina area of Alberta. These assets deliver stable production and contribute cash flow to fund future development and support ARC's dividend. |
2. | Operational excellence – ARC is focused on capital discipline and cost management to extract the maximum return on its investments while operating in a safe and environmentally responsible manner. Production from individual crude oil and natural gas wells naturally declines over time. In any one year, ARC approves a budget to drill new wells with the intent to first replace production declines and second to potentially increase production volumes and profitability. At times, ARC may also acquire strategic producing or undeveloped properties to enhance current production and reserves or to provide potential future drilling locations. Alternatively, it may strategically dispose of non-core assets that no longer meet its investment criteria. |
3. | Financial flexibility – ARC provides returns to shareholders through a combination of a monthly dividend, currently $0.05 per share outstanding per month, and the potential for capital appreciation. ARC’s long-term goal is to fund dividend payments and capital expenditures necessary for the replacement of production declines using funds from operations (1). ARC will finance value-creating activities through a combination of sources including funds from operations, proceeds from ARC’s Dividend Reinvestment Program (“DRIP”), reduced funding required under the Stock Dividend Program ("SDP"), proceeds from property dispositions, debt capacity, and when appropriate, equity issuance. ARC chooses to maintain prudent debt levels, targeting a maximum net debt to annualized funds from operations of less than two times during specific periods with a long-term target for net debt to be one to 1.5 times annualized funds from operations and less than 20 per cent of total capitalization over the long-term (1). |
4. | Top talent and strong leadership culture – ARC is committed to the attraction, retention and development of the best and brightest people in the industry. ARC’s employees conduct business every day in a culture of trust, respect, integrity and accountability. Building leadership talent at all levels of the organization is a key focus. ARC is also committed to corporate leadership through community investment, environmental reporting practices and open communication with all stakeholders. As of February 10, 2016, ARC had 502 employees with 269 professional, technical and support staff in the Calgary office, and 233 individuals located across ARC’s operating areas in western Canada. |
(1) | Funds from operations, net debt, and total capitalization are additional GAAP measures which may not be comparable to similar additional GAAP measures used by other entities. Refer to the section entitled “Additional GAAP Measures” contained within this MD&A and to Note 15 "Capital Management" in the financial statements. Also refer to the "Funds from Operations" section within this MD&A for a reconciliation of ARC’s net income to funds from operations and cash flow from operating activities. |
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Total Return to Shareholders
ARC's business plan has resulted in significant operational success and helped mitigate the headwinds of a challenging commodity price environment, resulting in a trailing five year annualized total return that exceeds the Standard & Poor's ("S&P")/Toronto Stock Exchange ("TSX") Exploration & Producers Index (Table 1).
Table 1
Total Returns (1) | Trailing One Year | Trailing Three Year | Trailing Five Year | |||
Dividends per share outstanding ($) | 1.20 | 3.60 | 6.00 | |||
Capital appreciation (depreciation) per share outstanding ($) | (8.46 | ) | (7.74 | ) | (8.71 | ) |
Total return per share outstanding (%) | (29.6 | ) | (21.1 | ) | (16.3 | ) |
Annualized total return per share outstanding (%) | (29.6 | ) | (7.6 | ) | (3.5 | ) |
S&P/TSX Exploration & Producers Index annualized total return (%) | (32.1 | ) | (15.6 | ) | (15.2 | ) |
(1) | Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to the section entitled "Non-GAAP Measures" contained within this MD&A. Calculated as at December 31, 2015. |
Since 2011, ARC’s production has grown by 30,751 boe per day, or 37 per cent, while its proved plus probable reserves have grown by 114.5 MMboe, or 20 per cent. Table 2 highlights ARC’s production and reserves for the last five years:
Table 2
2015 | 2014 | 2013 | 2012 | 2011 | ||||||
Production (boe/d) (1) | 114,167 | 112,387 | 96,087 | 93,546 | 83,416 | |||||
Daily production per thousand shares (2) | 0.34 | 0.35 | 0.31 | 0.31 | 0.29 | |||||
Proved plus probable reserves (MMboe) (3)(4) | 686.9 | 672.7 | 633.9 | 607.0 | 572.4 | |||||
Proved plus probable reserves per share (boe) | 2.0 | 2.1 | 2.0 | 2.0 | 2.0 |
(1) | Reported production amount is based on company interest before royalty burdens. |
(2) | Daily production per thousand shares represents annual average daily production divided by the diluted weighted average common shares for the respective years ending December 31. |
(3) | As determined by ARC’s independent reserve evaluator solely at December 31. |
(4) | Company gross reserves are the gross interest reserves before deduction of royalties and without including any royalty interests. For more information, see ARC’s Annual Information Form as filed on SEDAR at www.sedar.com and the news release entitled “ARC Resources Ltd. Announces the 8th Consecutive Year of ~200% Reserves Replacement, 2015 Finding and Development Costs for 2P Reserves of $6.97 and a Significant Increase in Montney Resource Estimates in 2015” dated February 10, 2016. |
Exhibit 1
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Exhibit 1a
ECONOMIC ENVIRONMENT
ARC’s 2015 financial and operating results were impacted by commodity prices and foreign exchange rates which are outlined in Table 3 below:
Table 3
Selected Benchmark Prices and Exchange Rates (1) | Three Months Ended | Twelve Months Ended | ||||||||||
December 31 | December 31 | |||||||||||
2015 | 2014 | % Change | 2015 | 2014 | % Change | |||||||
Brent (US$/bbl) | 44.69 | 77.07 | (42 | ) | 53.60 | 99.45 | (46 | ) | ||||
WTI oil (US$/bbl) | 42.16 | 73.20 | (42 | ) | 48.76 | 92.91 | (48 | ) | ||||
Edmonton Par (Cdn$/bbl) | 52.93 | 75.65 | (30 | ) | 57.20 | 94.46 | (39 | ) | ||||
Henry Hub NYMEX (US$/MMbtu) | 2.27 | 4.00 | (43 | ) | 2.66 | 4.41 | (40 | ) | ||||
AECO natural gas (Cdn$/Mcf) | 2.65 | 4.01 | (34 | ) | 2.77 | 4.42 | (37 | ) | ||||
Cdn$/US$ exchange rate | 1.34 | 1.14 | 18 | 1.28 | 1.10 | 16 |
(1) | The benchmark prices do not reflect ARC's realized sales prices. For average realized sales prices, refer to Table 13 in this MD&A. Prices and exchange rates presented above represent averages for the respective periods. |
Global crude oil prices continued their decline throughout the fourth quarter of 2015, as persistent oversupply in the market was compounded by OPEC's decision to not reduce production quotas, as well as the anticipation of new Iranian production hitting the market and fears of economic slowdown in China and other emerging economies. The WTI benchmark price averaged 42 per cent lower than the fourth quarter of 2014 and nine per cent lower than the third quarter of 2015. ARC’s crude oil price is primarily referenced to the Edmonton Par benchmark price, which fared moderately better than WTI owing to the decline in the Canadian dollar during 2015. The Edmonton Par price decreased 30 per cent compared to the fourth quarter of 2014 and six per cent from the third quarter of 2015. The differential between WTI and Edmonton Par in the fourth quarter of 2015 narrowed to an average discount of US$2.52, 62 per cent less than the fourth quarter of 2014 and 28 per cent less than the third quarter of 2015. The narrowing of the differential was largely driven by increased local demand for Canadian crude with the initiation of the reversal of Enbridge's Line 9.
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Subsequent to December 31, 2015, global crude oil prices have continued to deteriorate, with the WTI crude oil price dropping by approximately 25 per cent from the average realized price in the fourth quarter of 2015. Oversupply continues to be a concern as inventories remain high, delaying the effect of any supply/demand rebalancing.
Exhibit 2
North American natural gas prices, referenced by the average Henry Hub NYMEX price, experienced a pullback of 18 per cent in the fourth quarter of 2015 compared to the third quarter, and were markedly lower in the fourth quarter of 2015 relative to the same period in 2014, decreasing 43 per cent. ARC’s realized natural gas price is primarily referenced to the AECO hub, which was 34 per cent lower in the fourth quarter of 2015 compared to the fourth quarter of 2014 and five per cent lower compared to the third quarter of 2015. The lower prices were impacted by continued oversupply throughout the quarter, resulting in record storage levels at the close of injection season and warmer continental weather reducing normal seasonal demand. The oversupply was slightly alleviated by strong demand for Mexican exports and increased natural gas-fired power generation. Looking ahead to 2016, natural gas pricing is expected to experience continued weakness as a result of a relatively mild winter in the eastern half of North America to-date, and continued strong supply.
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Exhibit 2a
The Canadian dollar continued to weaken relative to the US dollar during the fourth quarter of 2015, averaging US$0.75 (Cdn$/US$1.34), as crude oil prices moved lower and the US Federal Reserve raised its interest rates for the first time in almost 10 years, signaling the continued economic recovery in the United States. The devaluation of the Canadian dollar relative to the US dollar serves to partially offset the impact of lower US dollar-denominated crude oil and natural gas prices for Canadian producers.
Exhibit 2b
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ANNUAL GUIDANCE AND FINANCIAL HIGHLIGHTS
Table 4 is a summary of ARC’s 2016 and 2015 guidance and a review of 2015 actual results. During this period of prolonged low commodity prices, ARC's strategy and principles remain unchanged; the Company is focused on balance sheet strength, value creation from the development of its high-quality asset base and long-term sustainability of its business. In response to the continued deterioration of commodity prices in late 2015 and early 2016, ARC is reducing its 2016 capital program to $390 million, down from the $550 million previously announced.
ARC's 2016 full-year guidance has been revised to incorporate reduced 2016 capital spending of approximately $390 million. Reflecting the 30 per cent reduction in capital spending, ARC's full-year average production guidance has been revised downward to a range of 116,000 to 120,000 boe per day from the previously guided range of 119,000 to 124,000 boe per day. ARC's full-year guidance for per boe operating costs was lowered to a range of $7.40 to $7.80 per boe to reflect the deferral of certain discretionary expenditures to future periods, and to reflect the continued focus on ARC's northeast British Columbia Montney assets, which have lower relative costs to operate. Lower power prices and the revision of estimates for prior periods benefited 2015 operating costs on a per boe basis; these items are not expected to impact 2016 operating costs, and as such, the guidance for 2016 operating costs on a per boe basis is higher relative to 2015 actual results. All other 2016 per boe guidance estimates that have changed from the original guidance announced on November 4, 2015 reflect revised production guidance for 2016.
Table 4
2016 Original Guidance (1) | 2016 Revised Guidance (1) | 2015 Guidance (2) | 2015 Actuals | % Variance from Guidance | ||||||
Production | ||||||||||
Crude oil (bbl/d) | 34,500 - 36,500 | 32,000 - 34,000 | 33,500 - 34,500 | 32,762 | (2 | ) | ||||
Condensate (bbl/d) | 3,200 - 3,600 | 3,000 - 3,400 | 3,400 - 3,800 | 3,430 | — | |||||
Natural gas (MMcf/d) | 465 - 475 | 460 - 470 | 435 - 440 | 444.9 | 1 | |||||
NGLs (bbl/d) | 4,000 - 4,500 | 3,800 - 4,200 | 3,700 - 3,900 | 3,819 | — | |||||
Total (boe/d) | 119,000 - 124,000 | 116,000 - 120,000 | 113,000 - 115,000 | 114,167 | — | |||||
Expenses ($/boe) | ||||||||||
Operating (3) | 7.70 - 8.10 | 7.40 - 7.80 | 7.50 - 7.70 | 7.15 | (5 | ) | ||||
Transportation | 2.40 - 2.70 | 2.40 - 2.70 | 2.30 - 2.50 | 2.33 | — | |||||
G&A expenses before share-based compensation plans | 1.45 - 1.55 | 1.55 - 1.65 | 1.65 - 1.70 | 1.48 | (10 | ) | ||||
G&A - share-based compensation plans (4) | 0.55 - 0.75 | 0.45 - 0.65 | 0.35 - 0.60 | 0.17 | (51 | ) | ||||
Interest | 1.00 - 1.20 | 1.10 - 1.30 | 1.10 - 1.30 | 1.22 | — | |||||
Current income tax (per cent of funds from operations) (5) | 0 - 5 | 0 - 5 | 0 - 2 | — | — | |||||
Capital expenditures before land purchases and net property acquisitions (dispositions) ($ millions) | 550 | 390 | 550 | 541.6 | (2 | ) | ||||
Land purchases and net property acquisitions (dispositions) ($ millions) | — | — | — | (67.7 | ) | N/A | ||||
Weighted average shares, diluted (millions) | 351 | 351 | 339 | 341 | 1 |
(1) | 2016 revised production guidance incorporates impact of approximately 1,300 boe per day of divested non-core crude oil assets at the end of 2015 and does not take into account the impact of any dispositions that may occur during 2016. |
(2) | Incorporates impact of approximately 3,600 boe per day of divested non-core assets throughout the first nine months of 2015 (75 per cent natural gas), which resulted in an annual volume impact of approximately 2,200 boe per day of production. |
(3) | Actual results for the year ended December 31, 2015 include a reduction of approximately $0.40 per boe due to a revision of estimates for prior period operating costs. |
(4) | Comprises expenses recognized under the RSU and PSU, Share Option and LTRSA Plans. In periods where substantial share price fluctuation occurs, ARC’s G&A expenses are subject to greater volatility. |
(5) | The 2015 and 2016 corporate tax estimates vary depending on level of commodity prices. |
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2015 annual production fell within the guidance range. Crude oil production was two per cent below the guidance range, reflecting the disposition of non-core properties producing approximately 500 barrels per day during the third quarter while natural gas production averaged slightly above the guidance range as a result of exceptional performance from ARC’s newest gas processing facility at Sunrise throughout the fourth quarter.
Exhibit 3
2015 Production Guidance
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On a per boe basis, operating costs were below the guidance range during 2015 with higher than expected production volumes for the first half of the year coupled with lower average electricity rates and diligent cost control over turnaround and maintenance activities completed during the year. In 2015, ARC’s G&A expenses averaged lower than the guidance range primarily due to decreased expenses under ARC’s share-based compensation plans. ARC recorded an income tax recovery for 2015, reflecting lower than anticipated taxable income related to decreased commodity prices.
Exhibit 3a
2015 Expenses Guidance
ARC incurred $541.6 million of capital expenditures during 2015. In addition, ARC spent $6.7 million on land purchases during the year and completed net dispositions of assets resulting in net proceeds of $74.4 million.
ARC's 2016 reduced capital program of $390 million will remain focused on balance sheet preservation and long-term value creation through continued development of ARC's low-cost, high-value northeast British Columbia Montney assets. The budget will allow ARC to hold northeast British Columbia facilities at capacity, progress the key infrastructure project at Dawson Phase III, and continue to delineate ARC's highly prospective Attachie asset. Capital allocation to ARC’s assets in Ante Creek, Pembina and Southeast Saskatchewan has been deferred while ARC concentrates investment in larger-scale projects that deliver superior rates of return in the current commodity price environment; ARC also awaits final details on the MRF (1) from the Alberta Government for its Alberta assets. Full-year 2016 annual average production is expected to be in the range of 116,000 to 120,000 boe per day.
Ongoing commodity price volatility may affect ARC's funds from operations and profitability on capital programs. As continued volatility is expected, ARC will continue to take steps to mitigate these risks, focus on capital discipline and cost control, and protect its strong financial position. ARC will adjust spending and the pace of development, if required, to ensure balance sheet strength is protected.
The guidance information presented is intended to provide shareholders with information on Management’s expectations for results from operations. Readers are cautioned that the guidance may not be appropriate for other purposes.
(1) | Modernized Royalty Framework. Refer to the section entitled “Royalties” contained within this MD&A. |
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2015 FOURTH QUARTER FINANCIAL AND OPERATING RESULTS
Financial Highlights
Table 5
Three Months Ended | Twelve Months Ended | |||||||||||
December 31 | December 31 | |||||||||||
($ millions, except per share and volume data) | 2015 | 2014 | % Change | 2015 | 2014 | % Change | ||||||
Funds from operations (1) | 200.7 | 251.7 | (20 | ) | 773.4 | 1,124.0 | (31 | ) | ||||
Funds from operations per share (1) | 0.58 | 0.79 | (27 | ) | 2.27 | 3.54 | (36 | ) | ||||
Net income (loss) | (55.0 | ) | 113.7 | (148 | ) | (342.7 | ) | 380.8 | (190 | ) | ||
Net income (loss) per share | (0.16 | ) | 0.36 | (144 | ) | (1.01 | ) | 1.20 | (184 | ) | ||
Dividends per share (2) | 0.30 | 0.30 | — | 1.20 | 1.20 | — | ||||||
Average daily production (boe/d) | 119,243 | 117,986 | 1 | 114,167 | 112,387 | 2 |
(1) | Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. |
(2) | Dividends per share are based on the number of shares outstanding at each dividend record date. |
Funds from Operations
ARC reports funds from operations in total and on a per share basis. Funds from operations does not have a standardized meaning prescribed by Canadian GAAP. Refer to the section entitled “Additional GAAP Measures” contained within this MD&A.
Table 6 is a reconciliation of ARC’s net income (loss) to funds from operations and cash flow from operating activities:
Table 6
Three Months Ended | Twelve Months Ended | |||||||
December 31 | December 31 | |||||||
($ millions) | 2015 | 2014 | 2015 | 2014 | ||||
Net income (loss) | (55.0 | ) | 113.7 | (342.7 | ) | 380.8 | ||
Adjusted for the following non-cash items: | ||||||||
DD&A and impairment | 263.0 | 279.4 | 1,065.4 | 758.5 | ||||
Accretion of ARO | 3.3 | 3.7 | 13.4 | 14.9 | ||||
E&E expenses | — | 9.5 | 46.9 | 39.4 | ||||
Deferred tax expense (recovery) | 3.2 | 23.5 | (6.8 | ) | 59.1 | |||
Unrealized gain on risk management contracts | (41.6 | ) | (212.6 | ) | (152.0 | ) | (205.3 | ) |
Unrealized loss on foreign exchange | 34.9 | 32.7 | 178.5 | 73.8 | ||||
Loss (gain) on disposal of petroleum and natural gas properties | (8.3 | ) | (0.1 | ) | (31.6 | ) | 1.8 | |
Other | 1.2 | 1.9 | 2.3 | 1.0 | ||||
Funds from operations | 200.7 | 251.7 | 773.4 | 1,124.0 | ||||
Net change in other liabilities | (4.0 | ) | 0.4 | (22.0 | ) | (20.4 | ) | |
Change in non-cash working capital | (20.9 | ) | 39.1 | (62.4 | ) | 49.4 | ||
Cash flow from operating activities | 175.8 | 291.2 | 689.0 | 1,153.0 |
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Details of the change in funds from operations from the three and twelve months ended December 31, 2014 to the three and twelve months ended December 31, 2015 are included in Table 7 below:
Table 7
Three Months Ended | Twelve Months Ended | |||||||
December 31 | December 31 | |||||||
$ millions | $/Share | $ millions | $/Share | |||||
Funds from operations – 2014 | 251.7 | 0.79 | 1,124.0 | 3.54 | ||||
Volume variance | ||||||||
Crude oil and liquids | (30.8 | ) | (0.10 | ) | (147.0 | ) | (0.46 | ) |
Natural gas | 14.1 | 0.04 | 67.4 | 0.21 | ||||
Price variance | ||||||||
Crude oil and liquids | (84.1 | ) | (0.26 | ) | (529.7 | ) | (1.67 | ) |
Natural gas | (67.4 | ) | (0.21 | ) | (305.1 | ) | (0.96 | ) |
Other Revenue | — | — | 0.4 | — | ||||
Realized gain on risk management contracts | 27.1 | 0.08 | 215.1 | 0.68 | ||||
Royalties | 40.4 | 0.13 | 194.7 | 0.62 | ||||
Expenses (recoveries) | ||||||||
Transportation | 3.3 | 0.01 | (5.4 | ) | (0.02 | ) | ||
Operating | 24.6 | 0.08 | 66.2 | 0.21 | ||||
G&A | 12.3 | 0.04 | 16.6 | 0.05 | ||||
Interest | (0.4 | ) | — | (3.7 | ) | (0.01 | ) | |
Current tax | 9.3 | 0.03 | 79.3 | 0.25 | ||||
Realized gain on foreign exchange | 0.6 | — | 0.6 | — | ||||
Diluted shares | — | (0.05 | ) | — | (0.17 | ) | ||
Funds from operations – 2015 | 200.7 | 0.58 | 773.4 | 2.27 |
Funds from operations decreased by 20 per cent in the fourth quarter of 2015 to $200.7 million from $251.7 million generated in the fourth quarter of 2014. The decrease reflects lower revenue due primarily to significantly lower realized commodity prices and reduced crude oil and liquids production in the fourth quarter of 2015 as compared to the fourth quarter of 2014. Increased natural gas production and realized gains on risk management contracts relative to the fourth quarter of the prior year along with lower royalties, operating costs, G&A expenses and current taxes partially offset the impact of the reduction in commodity prices.
For the year ended December 31, 2015, funds from operations decreased by $350.6 million to $773.4 million from $1,124 million in the prior year. This decrease reflects lower revenue net of royalties, partially offset by increased realized gains on risk management contracts, operating costs, G&A expenses and current taxes.
Exhibit 4
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Exhibit 4a
2015 Funds from Operations Sensitivity
Table 8 illustrates sensitivities of pre-hedged operating items to operational and business environment changes and the resulting impact on funds from operations per share:
Table 8
Impact on Annual Funds from Operations (6) | ||||||
Assumption | Change | $/Share | ||||
Business Environment (1) | ||||||
Crude oil price (US$ WTI/bbl) (2)(3) | 48.76 | 1.00 | 0.029 | |||
Natural gas price (Cdn$ AECO/Mcf) (2)(3) | 2.77 | 0.10 | 0.028 | |||
Cdn$/US$ exchange rate (2)(3)(4) | 1.28 | 0.01 | 0.011 | |||
Interest rate on floating-rate debt (2) | 2.8 | % | 1.0 | % | — | |
Operational | ||||||
Crude oil and liquids production volumes (bbl/d) (5) | 40,011 | 1.0 | % | 0.014 | ||
Natural gas production volumes (MMcf/d) (5) | 444.9 | 1.0 | % | 0.009 | ||
Operating expenses ($/boe) (5) | 7.15 | 1.0 | % | 0.006 | ||
G&A expenses ($/boe) (5) | 1.65 | 10.0 | % | 0.020 |
(1) | Calculations are performed independently and may not be indicative of actual results that would occur when multiple variables change at the same time. |
(2) | Prices and rates are indicative of published prices for the year ended December 31, 2015. See Table 13 of this MD&A for additional details. The calculated impact on funds from operations would only be applicable within a limited range of these amounts. |
(3) | Analysis does not include the effect of risk management contracts. |
(4) | Includes impact of foreign exchange on crude oil, condensate, and NGLs prices that are presented in US dollars. |
(5) | Operational assumptions are based upon results for the year ended December 31, 2015. |
(6) | Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. |
Exhibit 5
(1) | Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. |
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Net Income (Loss)
A net loss of $55 million (loss of $0.16 per share) was incurred in the fourth quarter of 2015, a $168.7 million ($0.52 per share) decrease compared to net income of $113.7 million (income of $0.36 per share) in the fourth quarter of 2014. Lower revenue net of royalties and decreased gains on risk management contracts reduced net income while lower operating costs, G&A expenses and income taxes, as well as higher gains on disposal of petroleum and natural gas properties served to partially offset the decrease. ARC also recorded lower DD&A charges in the fourth quarter of 2015 as compared to the same period in the prior year, which were partially offset by increased impairment charges.
Exhibit 6
(1) | Includes loss on foreign exchange, loss on short-term investments, and gain on disposal of PP&E. |
During the year ended December 31, 2015, ARC incurred a net loss of $342.7 million (loss of $1.01 per share), compared to net income of $380.8 million (income of $1.20 per share) earned during the prior year. Lower commodity prices during 2015 resulted in lower revenue net of royalties, however, the impact of falling prices was partially offset by increased gains on risk management contracts. ARC also recognized lower operating costs, lower G&A expenses, higher gains on disposal of petroleum and natural gas properties, and lower current and deferred taxes during the year. While ARC's DD&A charges were lower in 2015 as compared to the prior year, higher impairment charges were recognized in 2015. Additionally, increased foreign exchange losses were recognized in the current year relating to the revaluation of ARC’s U.S. dollar denominated long-term debt outstanding.
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Exhibit 6a
(1) | Includes accretion, interest and financing expenses, loss on short-term investments, and gain on disposal of PP&E. |
Production
Table 9
Three Months Ended | Twelve Months Ended | |||||||||||
December 31 | December 31 | |||||||||||
Production | 2015 | 2014 | % Change | 2015 | 2014 | % Change | ||||||
Light and medium crude oil (bbl/d) | 33,124 | 36,276 | (9 | ) | 31,827 | 35,467 | (10 | ) | ||||
Heavy oil (bbl/d) | 775 | 1,166 | (34 | ) | 935 | 1,058 | (12 | ) | ||||
Condensate (bbl/d) | 3,631 | 3,448 | 5 | 3,430 | 3,667 | (6 | ) | |||||
Natural gas (MMcf/d) | 469.1 | 432.1 | 9 | 444.9 | 406.1 | 10 | ||||||
NGLs (bbl/d) | 3,523 | 5,075 | (31 | ) | 3,819 | 4,518 | (15 | ) | ||||
Total production (boe/d) | 119,243 | 117,986 | 1 | 114,167 | 112,387 | 2 | ||||||
% Natural gas production | 66 | 61 | 8 | 65 | 60 | 8 | ||||||
% Crude oil and liquids production | 34 | 39 | (13 | ) | 35 | 40 | (13 | ) |
During both the three months and year ended December 31, 2015, crude oil and liquids production decreased 11 per cent from the same periods of the prior year. The decrease in crude oil and liquids production primarily reflects natural declines associated with reduced drilling activity and the disposition of certain non-core assets in Southwestern Saskatchewan in the third quarter of 2015 which had been producing approximately 500 boe per day prior to disposal. The decrease was partially offset by additional production at Tower following the battery expansion that was completed during the fourth quarter.
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Natural gas production was 469.1 MMcf per day in the fourth quarter of 2015, an increase of nine per cent from the 432.1 MMcf per day produced in the fourth quarter of 2014. The increase is mainly attributed to new production from drilling throughout 2015 in northeastern British Columbia, particularly at Sunrise to fill ARC's new 60 MMcf per day natural gas processing facility which was commissioned during the third quarter of 2015. The increase in natural gas production was partially offset by the disposition of certain non-core assets in South Central Alberta in the second quarter of 2015 which had been producing approximately 14.4 MMcf per day prior to disposal. For the year ended December 31, 2015, natural gas production increased by 10 per cent as new production was brought on throughout 2015 at Sunrise and Parkland which served to offset the impact of lost production due to turnarounds during the year and the second quarter disposition.
Exhibit 7
ARC Resources Ltd. | Page 14 |
During the fourth quarter of 2015, ARC drilled five natural gas wells (100 per cent ARC) on operated properties. For the year ended December 31, 2015, ARC drilled 60 gross wells (59 net wells) on operated properties consisting of 33 gross (32 net) oil wells, 21 gross (21 net) natural gas wells, five gross (five net) liquids-rich natural gas wells, and one gross (one net) service well. Table 10 summarizes ARC’s production by core area for the fourth quarter of 2015 and 2014:
Table 10
Three Months Ended December 31, 2015 | ||||||||||
Production | Total | Crude Oil | Condensate | Natural Gas | NGLs | |||||
Core Area (1) | (boe/d) | (bbl/d) | (bbl/d) | (MMcf/d) | (bbl/d) | |||||
Northeast BC | 73,964 | 6,344 | 2,677 | 379.8 | 1,637 | |||||
Northern AB | 20,780 | 7,394 | 703 | 68.9 | 1,194 | |||||
Pembina | 10,368 | 7,618 | 195 | 12.8 | 432 | |||||
South Central AB (2) | 4,821 | 3,593 | 6 | 6.4 | 150 | |||||
Southeast SK & MB (3) | 9,310 | 8,950 | 50 | 1.2 | 110 | |||||
Total | 119,243 | 33,899 | 3,631 | 469.1 | 3,523 |
Three Months Ended December 31, 2014 | ||||||||||
Production | Total | Crude Oil | Condensate | Natural Gas | NGLs | |||||
Core Area (1) | (boe/d) | (bbl/d) | (bbl/d) | (MMcf/d) | (bbl/d) | |||||
Northeast BC | 63,675 | 4,372 | 2,420 | 325.0 | 2,704 | |||||
Northern AB | 22,583 | 8,496 | 748 | 70.3 | 1,626 | |||||
Pembina | 12,068 | 9,331 | 167 | 12.8 | 444 | |||||
South Central AB (2) | 8,645 | 4,542 | 60 | 23.0 | 213 | |||||
Southeast SK & MB (3) | 11,015 | 10,701 | 53 | 1.0 | 88 | |||||
Total | 117,986 | 37,442 | 3,448 | 432.1 | 5,075 |
(1) | Provincial references: "AB" is Alberta, "BC" is British Columbia, "SK" is Saskatchewan, "MB" is Manitoba. |
(2) | During the second quarters of 2015 and 2014, ARC disposed of certain non-core assets in this district. Each disposition included assets that had been producing approximately 2,400 boe per day prior to disposal. An additional 500 boe per day were disposed from this district toward the end of the third quarter of 2015. |
(3) | In December 2015, ARC disposed of certain non-core assets in this district that had been producing approximately 1,300 boe per day prior to disposal. |
Exhibit 8
ARC Resources Ltd. | Page 15 |
Table 10a summarizes ARC’s production by core area for the twelve months ended December 31, 2015 and 2014:
Table 10a
Twelve Months Ended December 31, 2015 | ||||||||||
Production | Total | Crude Oil | Condensate | Natural Gas | NGLs | |||||
Core Area (1) | (boe/d) | (bbl/d) | (bbl/d) | (MMcf/d) | (bbl/d) | |||||
Northeast BC | 66,022 | 3,406 | 2,461 | 350.8 | 1,687 | |||||
Northern AB | 21,035 | 7,497 | 710 | 68.5 | 1,402 | |||||
Pembina | 10,992 | 8,227 | 175 | 12.9 | 446 | |||||
South Central AB (2) | 6,166 | 3,996 | 33 | 11.6 | 196 | |||||
Southeast SK & MB (3) | 9,952 | 9,636 | 51 | 1.1 | 88 | |||||
Total | 114,167 | 32,762 | 3,430 | 444.9 | 3,819 |
Twelve Months Ended December 31, 2014 | ||||||||||
Production | Total | Crude Oil | Condensate | Natural Gas | NGLs | |||||
Core Area (1) | (boe/d) | (bbl/d) | (bbl/d) | (MMcf/d) | (bbl/d) | |||||
Northeast BC | 57,669 | 3,384 | 2,580 | 296.4 | 2,302 | |||||
Northern AB | 23,339 | 9,547 | 811 | 68.8 | 1,511 | |||||
Pembina | 11,391 | 8,779 | 163 | 12.3 | 405 | |||||
South Central AB (2) | 9,190 | 4,321 | 70 | 27.5 | 220 | |||||
Southeast SK & MB (3) | 10,798 | 10,494 | 43 | 1.1 | 80 | |||||
Total | 112,387 | 36,525 | 3,667 | 406.1 | 4,518 |
(1) | Provincial references: "AB" is Alberta, "BC" is British Columbia, "SK" is Saskatchewan, "MB" is Manitoba. |
(2) | During the second quarters of 2015 and 2014, ARC disposed of certain non-core assets in this district. Each disposition included assets that had been producing approximately 2,400 boe per day prior to disposal. An additional 500 boe per day were disposed from this district toward the end of the third quarter of 2015. |
(3) | In December 2015, ARC disposed of certain non-core assets in this district that had been producing approximately 1,300 boe per day prior to disposal. |
Exhibit 8a
ARC Resources Ltd. | Page 16 |
Sales of Crude Oil, Natural Gas, Condensate, NGLs and Other Income
Sales revenue from crude oil, natural gas, condensate, NGLs and other income decreased significantly in both the fourth quarter of 2015 and for the full year as compared to the same periods in 2014. The decreases reflect lower average realized commodity prices for all products in 2015 compared to 2014 as well as decreased crude oil and liquids production volumes.
A breakdown of sales revenue by product is outlined in Table 11:
Table 11
Three Months Ended | Twelve Months Ended | |||||||||||
December 31 | December 31 | |||||||||||
Sales revenue by product ($ millions) | 2015 | 2014 | % Change | 2015 | 2014 | % Change | ||||||
Crude oil | 153.5 | 249.7 | (39 | ) | 640.1 | 1,208.4 | (47 | ) | ||||
Condensate | 16.6 | 23.5 | (29 | ) | 67.4 | 125.6 | (46 | ) | ||||
Natural gas | 111.7 | 165.0 | (32 | ) | 467.9 | 705.6 | (34 | ) | ||||
NGLs | 3.5 | 15.3 | (77 | ) | 14.9 | 65.1 | (77 | ) | ||||
Total sales revenue from crude oil, natural gas, condensate and NGLs | 285.3 | 453.5 | (37 | ) | 1,190.3 | 2,104.7 | (43 | ) | ||||
Other income | 0.6 | 0.6 | — | 3.4 | 3.0 | 13 | ||||||
Total sales revenue | 285.9 | 454.1 | (37 | ) | 1,193.7 | 2,107.7 | (43 | ) |
Exhibit 9
While ARC’s production mix on a per boe basis is weighted more heavily to natural gas than to crude oil and liquids, ARC's revenue contribution is more heavily weighted to crude oil and liquids production as shown by the table below:
Table 12
Three Months Ended | Twelve Months Ended | |||
December 31 | December 31 | |||
Revenue by Product Type | 2015 | 2014 | 2015 | 2014 |
% of Total Revenue | % of Total Revenue | % of Total Revenue | % of Total Revenue | |
Crude oil and liquids | 61 | 64 | 61 | 66 |
Natural gas | 39 | 36 | 39 | 34 |
Total sales revenue | 100 | 100 | 100 | 100 |
ARC Resources Ltd. | Page 17 |
Commodity Prices Prior to Hedging
Table 13
Three Months Ended | Twelve Months Ended | |||||||||||
December 31 | December 31 | |||||||||||
2015 | 2014 | % Change | 2015 | 2014 | % Change | |||||||
Average Benchmark Prices | ||||||||||||
AECO natural gas (Cdn$/Mcf) | 2.65 | 4.01 | (34 | ) | 2.77 | 4.42 | (37 | ) | ||||
WTI oil (US$/bbl) | 42.16 | 73.20 | (42 | ) | 48.76 | 92.91 | (48 | ) | ||||
Cdn$/US$ exchange rate | 1.34 | 1.14 | 18 | 1.28 | 1.10 | 16 | ||||||
WTI oil (Cdn$/bbl) | 56.49 | 83.45 | (32 | ) | 62.41 | 102.20 | (39 | ) | ||||
Edmonton Par (Cdn$/bbl) | 52.93 | 75.65 | (30 | ) | 57.20 | 94.46 | (39 | ) | ||||
ARC Average Realized Prices Prior to Hedging | ||||||||||||
Crude oil ($/bbl) | 49.24 | 72.49 | (32 | ) | 53.53 | 90.64 | (41 | ) | ||||
Condensate ($/bbl) | 49.80 | 74.04 | (33 | ) | 53.84 | 93.81 | (43 | ) | ||||
Natural gas ($/Mcf) | 2.59 | 4.15 | (38 | ) | 2.88 | 4.76 | (39 | ) | ||||
NGLs ($/bbl) | 10.73 | 32.69 | (67 | ) | 10.70 | 39.45 | (73 | ) | ||||
Total average realized commodity price prior to other income and hedging ($/boe) | 26.01 | 41.78 | (38 | ) | 28.57 | 51.31 | (44 | ) | ||||
Other income ($/boe) | 0.05 | 0.05 | — | 0.08 | 0.07 | 14 | ||||||
Total average realized price prior to hedging ($/boe) | 26.06 | 41.83 | (38 | ) | 28.65 | 51.38 | (44 | ) |
In the fourth quarter of 2015, WTI decreased 42 per cent to US$42.16 per barrel as compared to US$73.20 per barrel in the same period in 2014. Similarly, ARC’s realized crude oil price decreased by 32 per cent over the same time period, averaging $49.24 per barrel. During the fourth quarter of 2015, the differential between WTI and Edmonton posted prices narrowed to an average discount of US$2.52 per barrel compared to US$6.58 per barrel in the same period in 2014. During the same period, the average exchange rate for the Canadian dollar as compared to the US dollar weakened from $1.14 to $1.34. The narrowing of the differential combined with a weaker Canadian dollar served to partially mitigate the overall impact of the decrease in WTI on ARC's average realized prices.
For the year ended December 31, 2015, ARC's average realized crude oil price fell by 41 per cent as compared to the year ended December 31, 2014. This price decrease is primarily attributed to the 48 per cent decrease in WTI over the same time period, partially offset by the effect of a narrowed differential between WTI and Edmonton Par crude oil prices and a weakened Canadian dollar.
Natural gas prices decreased in the fourth quarter and for the year ended December 31, 2015 as compared to the same periods in 2014. Year-over-year North American supply exceeded demand, leaving inventory levels much higher than in the prior year. ARC's average realized natural gas price for the year ended December 31, 2015 of $2.88 per Mcf was higher than the 2014 average AECO monthly index price due in part to ARC's higher than average heat content in its natural gas. Approximately 20 per cent of ARC's natural gas production is sold at Station 2 in British Columbia which has experienced volatile pricing throughout the second half of the year, primarily as a result of maintenance activities on all western Canadian pipelines, leading to insufficient take-away capacity. As a result, ARC's average realized natural gas price for the fourth quarter of 2015 of $2.59 per Mcf was modestly lower than the average AECO monthly index price during the period. ARC has been able to partially mitigate the impact of Station 2 pricing through the physical diversification of its sales points. ARC maintains a diversified sales portfolio that allows some flexibility on a portion of its natural gas sales between monthly average and daily spot pricing at sales hubs in western Canada and the mid-western United States.
ARC Resources Ltd. | Page 18 |
Risk Management
ARC maintains a risk management program to reduce the volatility of revenues, increase the certainty of funds from operations, and to protect acquisition and development economics. ARC’s risk management program is governed by certain guidelines approved by the Board of Directors (the "Board"). These guidelines currently restrict risk management contracts to a maximum of 55 per cent of total forecast production where a specific commodity (crude oil or natural gas) cannot exceed a maximum of 70 per cent of forecast production for that commodity over the next two years, and with a maximum of 25 per cent of forecast natural gas production in risk management contracts beyond two years and up to five years. ARC’s risk management program guidelines allow for further risk management contracts on anticipated volumes associated with new production arising from specific capital projects and acquisitions or to further protect cash flows for a specific period with approval of the Board.
Gains and losses on risk management contracts are composed of both realized gains and losses, representing the portion of risk management contracts that have settled in cash during the period, and unrealized gains or losses that represent the change in the mark-to-market position of those contracts throughout the period. ARC does not employ hedge accounting for any of its risk management contracts currently in place. ARC considers all of its risk management contracts to be effective economic hedges of its underlying business transactions.
Table 14 summarizes the total gain or loss on risk management contracts for the fourth quarter of 2015 compared to the same period in 2014:
Table 14
Risk Management Contracts ($ millions) | Crude Oil & Liquids | Natural Gas | Foreign Currency | Power | Q4 2015 Total | Q4 2014 Total | ||||||
Realized gain (loss) on contracts (1) | 12.7 | 43.2 | (3.2 | ) | (0.8 | ) | 51.9 | 24.8 | ||||
Unrealized gain (loss) on contracts (2) | 20.0 | 18.5 | 3.9 | (0.8 | ) | 41.6 | 212.6 | |||||
Gain (loss) on risk management contracts | 32.7 | 61.7 | 0.7 | (1.6 | ) | 93.5 | 237.4 |
(1) | Represents actual cash settlements or receipts under the respective contracts. |
(2) | Represents the change in fair value of the contracts during the period. |
Table 14a summarizes the total gain or loss on risk management contracts for the year ended December 31, 2015 compared to the same period in 2014:
Table 14a
Risk Management Contracts ($ millions) | Crude Oil & Liquids | Natural Gas | Foreign Currency | Power | 2015 Total | 2014 Total | ||||||
Realized gain (loss) on contracts (1) | 55.8 | 141.2 | (9.9 | ) | (1.1 | ) | 186.0 | (29.1 | ) | |||
Unrealized gain (loss) on contracts (2) | 39.4 | 109.5 | 4.1 | (1.0 | ) | 152.0 | 205.3 | |||||
Gain (loss) on risk management contracts | 95.2 | 250.7 | (5.8 | ) | (2.1 | ) | 338.0 | 176.2 |
(1) | Represents actual cash settlements or receipts under the respective contracts. |
(2) | Represents the change in fair value of the contracts during the period. |
During the three and twelve months ended December 31, 2015, ARC recorded gains of $93.5 million and $338 million, respectively, on its risk management contracts. These gains comprised realized gains of $51.9 million and unrealized gains of $41.6 million for the fourth quarter and realized gains of $186 million and unrealized gains of $152 million for the year ended December 31, 2015. The realized gains reflect positive cash settlements received on crude oil contracts with an average floor price of US$90/bbl for the first and second quarters of 2015, crude oil swaps with an average price of $74.77 in the third and fourth quarters, crude oil contracts with an average floor price of $61.80 in the fourth quarter, and on natural gas contracts with an average floor price of $3.94/MMbtu throughout the year. These realized gains are partially offset by realized losses on forward foreign currency and power contracts.
ARC's fourth quarter 2015 unrealized gains on crude oil contracts reflect lower Canadian WTI prices in the forward price curve. During the same period, unrealized gains on natural gas contracts reflect lower forward NYMEX Henry Hub prices, offset by slightly narrower AECO basis through 2019. For the year ended December 31, 2015, ARC's unrealized gains on natural gas contracts primarily reflect lower forward NYMEX Henry Hub prices. Losses for the three months and year ended December 31, 2015 on electricity contracts reflect lower power prices in the forward price curve.
ARC’s risk management contracts provide protection from natural gas prices on 173,400 MMbtu per day for 2016. ARC has also executed long-term natural gas contracts on 154,500 MMbtu per day for 2017, 127,900 MMbtu per day for 2018, 68,400 MMbtu per day for 2019, and 56,800 for 2020. In addition, ARC has AECO basis swap contracts in place,
ARC Resources Ltd. | Page 19 |
fixing the AECO price received on 140,000 MMbtu per day for 2016, 150,000 MMbtu per day for 2017, 95,000 MMbtu per day for 2018, 60,000 MMbtu per day for 2019, and 10,000 MMbtu per day for 2020.
For crude oil, ARC has 10,000 barrels per day of crude oil production hedged for 2016. In addition, ARC has hedged 3,000 barrels per day of production for the first half of 2017. ARC also has MSW basis swap contracts in place for 2016, fixing the discount between WTI and the mixed sweet crude grade price at Edmonton.
Table 15 summarizes ARC’s average crude oil and natural gas hedged volumes for 2016 through 2020 as at the date of this MD&A. For a complete listing and terms of ARC’s hedging contracts at December 31, 2015, see Note 16 “Financial Instruments and Market Risk Management” in the financial statements.
Table 15
Hedge Positions Summary (1) | ||||||||||||||||||||
As at February 10, 2016 | 2016 | 2017 | 2018 | 2019 | 2020 | |||||||||||||||
Crude Oil - Cdn$ WTI (2) | Cdn$/bbl | bbl/d | Cdn$/bbl | bbl/d | Cdn$/bbl | bbl/d | Cdn$/bbl | bbl/d | Cdn$/bbl | bbl/d | ||||||||||
Ceiling | 83.38 | 3,000 | 83.38 | 1,488 | — | — | — | — | — | — | ||||||||||
Floor | 70.00 | 3,000 | 70.00 | 1,488 | — | — | — | — | — | — | ||||||||||
Swap | 77.20 | 7,000 | — | — | — | — | — | — | — | — | ||||||||||
Crude Oil - MSW (Differential to WTI) (3) | US$/bbl | bbl/d | US$/bbl | bbl/d | US$/bbl | bbl/d | US$/bbl | bbl/d | US$/bbl | bbl/d | ||||||||||
Swap | (3.75 | ) | 9,500 | — | — | — | — | — | — | — | — | |||||||||
Natural Gas - NYMEX (4) | US$/MMbtu | MMbtu/d | US$/MMbtu | MMbtu/d | US$/MMbtu | MMbtu/d | US$/MMbtu | MMbtu/d | US$/MMbtu | MMbtu/d | ||||||||||
Ceiling | 4.79 | 105,000 | 4.81 | 145,000 | 4.92 | 90,000 | 5.00 | 40,000 | — | — | ||||||||||
Floor | 4.00 | 105,000 | 4.00 | 145,000 | 4.00 | 90,000 | 4.00 | 40,000 | — | — | ||||||||||
Swap | 4.00 | 40,000 | — | — | — | — | — | — | — | — | ||||||||||
Natural Gas - AECO (5) | Cdn$/GJ | GJ/d | Cdn$/GJ | GJ/d | Cdn$/GJ | GJ/d | Cdn$/GJ | GJ/d | Cdn$/GJ | GJ/d | ||||||||||
Ceiling | — | — | — | — | — | — | 3.30 | 10,000 | 3.60 | 30,000 | ||||||||||
Floor | — | — | — | — | — | — | 3.00 | 10,000 | 3.08 | 30,000 | ||||||||||
Swap | 2.99 | 30,000 | 2.75 | 10,000 | 2.96 | 40,000 | 3.16 | 20,000 | 3.35 | 30,000 | ||||||||||
Natural Gas - AECO Basis (6) | AECO/NYMEX | MMbtu/d | AECO/NYMEX | MMbtu/d | AECO/NYMEX | MMbtu/d | AECO/NYMEX | MMbtu/d | AECO/NYMEX | MMbtu/d | ||||||||||
Swap (percentage of NYMEX) | 90.3 | 140,000 | 89.3 | 150,000 | 84.5 | 95,000 | 82.6 | 60,000 | 82.5 | 10,000 |
(1) | The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. All positions are financially settled against the benchmark prices disclosed in Note 16 “Financial Instruments and Market Risk Management” in the financial statements. |
(2) | Crude oil prices referenced to WTI, multiplied by the Bank of Canada monthly average noon day rate. |
(3) | MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton, calculated on a monthly weighted average basis in US$. |
(4) | Natural gas prices referenced to NYMEX Henry Hub. |
(5) | Natural gas prices referenced to AECO 7(a) index. |
(6) | ARC sells the majority of its natural gas production based on AECO pricing. To reduce the risk of weak basis pricing (AECO relative to NYMEX Henry Hub), ARC has hedged a portion of production by tying ARC's price to a percentage of the NYMEX Henry Hub natural gas price. |
The fair value of ARC’s risk management contracts at December 31, 2015 was a net asset of $409.9 million, representing the expected market price to settle ARC’s contracts at the balance sheet date after any adjustments for credit risk. This may differ from what will eventually be settled in future periods.
ARC Resources Ltd. | Page 20 |
Exhibit 10
Operating Netbacks
ARC’s fourth quarter and 2015 netbacks prior to hedging were $15.63 per boe and $16.69 per boe, respectively, representing decreases of 37 per cent and 49 per cent as compared to the same periods in 2014.
ARC’s fourth quarter and 2015 netbacks, including realized hedging gains and losses, were $20.36 per boe and $21.15 per boe, respectively, representing decreases of 25 per cent and 35 per cent as compared to the same periods in 2014.
The components of operating netbacks for the fourth quarter of 2015 compared to the same period in 2014 are summarized in Table 16:
Table 16
Netbacks (1) | Crude Oil | Heavy Oil | Condensate | Natural Gas | NGLs | Q4 2015 Total | Q4 2014 Total | |||||||
($/bbl) | ($/bbl) | ($/bbl) | ($/Mcf) | ($/bbl) | ($/boe) | ($/boe) | ||||||||
Average sales price | 49.66 | 31.26 | 49.80 | 2.59 | 10.73 | 26.01 | 41.78 | |||||||
Other income | — | — | — | — | — | 0.05 | 0.05 | |||||||
Total sales | 49.66 | 31.26 | 49.80 | 2.59 | 10.73 | 26.06 | 41.83 | |||||||
Royalties | (5.65 | ) | (1.03 | ) | (7.95 | ) | (0.04 | ) | (1.91 | ) | (2.03 | ) | (5.77 | ) |
Transportation | (2.54 | ) | (0.48 | ) | (3.10 | ) | (0.30 | ) | (7.49 | ) | (2.19 | ) | (2.51 | ) |
Operating expenses (2) | (11.45 | ) | (13.03 | ) | (5.19 | ) | (0.66 | ) | (6.15 | ) | (6.21 | ) | (8.55 | ) |
Netback prior to hedging | 30.02 | 16.72 | 33.56 | 1.59 | (4.82 | ) | 15.63 | 25.00 | ||||||
Hedging gain (3) | 3.89 | — | — | 0.93 | — | 4.73 | 2.29 | |||||||
Netback after hedging | 33.91 | 16.72 | 33.56 | 2.52 | (4.82 | ) | 20.36 | 27.29 | ||||||
% of total netback | 46 | 1 | 5 | 49 | (1 | ) | 100 | 100 |
(1) | Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to the section entitled "Non-GAAP Measures" contained within this MD&A. |
(2) | Composed of direct costs incurred to operate crude oil and natural gas wells. A number of assumptions have been made in allocating these costs between crude oil, heavy oil, condensate, natural gas and NGLs production. |
(3) | Includes realized cash gains and losses on risk management contracts. |
ARC Resources Ltd. | Page 21 |
Exhibit 11
(1) | Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to the section entitled "Non-GAAP Measures" contained within this MD&A. |
The components of operating netbacks for the year ended December 31, 2015 compared to the same period in 2014 are summarized in Table 16a:
Table 16a
Netbacks (1) | Crude Oil | Heavy Oil | Condensate | Natural Gas | NGLs | 2015 Total | 2014 Total | |||||||
($/bbl) | ($/bbl) | ($/bbl) | ($/Mcf) | ($/bbl) | ($/boe) | ($/boe) | ||||||||
Average sales price | 53.94 | 39.70 | 53.84 | 2.88 | 10.70 | 28.57 | 51.31 | |||||||
Other income | — | — | — | — | — | 0.08 | 0.07 | |||||||
Total sales | 53.94 | 39.70 | 53.84 | 2.88 | 10.70 | 28.65 | 51.38 | |||||||
Royalties | (5.72 | ) | (0.87 | ) | (9.03 | ) | (0.14 | ) | (2.12 | ) | (2.48 | ) | (7.26 | ) |
Transportation | (2.57 | ) | (0.52 | ) | (3.00 | ) | (0.32 | ) | (7.81 | ) | (2.33 | ) | (2.23 | ) |
Operating expenses (2) | (12.78 | ) | (10.38 | ) | (5.78 | ) | (0.80 | ) | (6.05 | ) | (7.15 | ) | (8.88 | ) |
Netback prior to hedging | 32.87 | 27.93 | 36.03 | 1.62 | (5.28 | ) | 16.69 | 33.01 | ||||||
Hedging gain (loss) (3) | 4.59 | — | — | 0.82 | — | 4.46 | (0.65 | ) | ||||||
Netback after hedging | 37.46 | 27.93 | 36.03 | 2.44 | (5.28 | ) | 21.15 | 32.36 | ||||||
% of total netback | 50 | 1 | 5 | 45 | (1 | ) | 100 | 100 |
(1) | Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to the section entitled "Non-GAAP Measures" contained within this MD&A. |
(2) | Composed of direct costs incurred to operate crude oil and natural gas wells. A number of assumptions have been made in allocating these costs between crude oil, heavy oil, condensate, natural gas and NGLs production. |
(3) | Includes realized cash gains and losses on risk management contracts. |
Royalties
ARC pays royalties to the respective provincial governments and landowners of the four western Canadian provinces in which it operates. Approximately 79 per cent of these royalties are Crown royalties. Each province that ARC operates in has established a separate and distinct royalty regime which impacts ARC’s average corporate royalty rate.
In British Columbia, the majority of ARC’s royalty expense stems from production of natural gas and associated liquids. While condensate and NGLs have a flat royalty rate of 20 per cent of sales revenue, the royalty rates for natural gas
ARC Resources Ltd. | Page 22 |
are based on the drill date of a well and a producer price. All wells spud on or after April 1, 2014 receive a minimum six per cent royalty with additional royalty credits available for horizontal wells drilled to depths greater than 1,900 meters. Wells drilled prior to that date receive a minimum three per cent royalty.
In Alberta, the majority of ARC’s royalties are related to oil production where royalty rates are based on reference prices, production levels and well depths. Similarly, most royalties remitted in Saskatchewan and Manitoba relate to oil production. Royalty calculations in these provinces are based on the classification of the oil product and well productivity.
Each province has various incentive programs in place to promote drilling by reducing the overall royalty expense for producers and offsetting gathering and processing costs. In most cases, the incentive period lasts for a finite period of time (usually twelve months upon commencement of production), after which point the royalty rate usually increases depending on the production rate of the well and prevailing market commodity prices.
In 2016, the provincial government of Alberta announced the key highlights of a proposed Modernized Royalty Framework ("MRF") that will be effective on January 1, 2017. These highlights include providing royalty incentives for the efficient development of conventional crude oil, natural gas, and NGL resources, no changes to the royalty structure of wells drilled prior to 2017 for a 10-year period from the royalty program's implementation date, the replacement of royalty credits/holidays on conventional wells by a revenue minus cost framework with a post-payout royalty rate based on commodity prices, the reduction of royalty rates for mature wells, and a neutral internal rate of return for any given play compared to the current royalty framework. While the provincial government of Alberta has not yet released all of the details of the MRF, the changes are not currently expected to have a material impact on ARC's results of operations. ARC will evaluate the impact of the MRF on the Company’s expected results of operations and cash flows as more details are released.
Total royalties as a percentage of pre-hedged commodity product sales revenue decreased from 13.8 per cent ($5.77 per boe) in the fourth quarter of 2014 to 7.8 per cent ($2.03 per boe) in the fourth quarter of 2015 reflecting the "sliding scale" effect of royalty rates with the decrease in average commodity prices during that time period. Similarly, total royalties decreased from $62.7 million in the fourth quarter of 2014 to $22.3 million in the fourth quarter of 2015. For the year ended December 31, 2015, total royalties represented 8.7 per cent of pre-hedged commodity product sales ($2.48 per boe) as compared to 14.1 per cent ($7.26 per boe) for the same period in 2014. The decrease in the royalty rate during the year ended December 31, 2015 as compared to the same period of the prior year also reflects the impact of the decrease in commodity prices on royalties over the same periods.
Exhibit 12
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Operating and Transportation Expenses
Operating expenses decreased $2.34 per boe to $6.21 per boe in the fourth quarter of 2015 compared to $8.55 per boe in the fourth quarter of 2014. On an absolute dollar basis, operating expenses have also decreased by $24.6 million or 27 per cent in the fourth quarter of 2015 as compared to the fourth quarter of 2014. For the year ended December 31, 2015 operating expenses decreased by $66.2 million or $1.73 per boe compared to the prior year. The decrease in operating costs for both the three months and year ended December 31, 2015 is mainly a result of reduced maintenance activity levels, the disposition of certain non-core assets throughout the year, increased production volumes from new wells with relatively lower average operating costs, and diligent cost control efforts including negotiating service cost decreases with many of ARC's suppliers throughout 2015. Additionally, electricity costs were lower in 2015 than 2014 with an average Alberta Power Pool Rate of $33.41 per megawatt hour in 2015 as compared to an average of $49.63 per megawatt hour in 2014, further reducing operating costs year-over-year.
ARC hedges a portion of its electricity costs using financial risk management contracts that do not qualify for hedge accounting. The gains and losses associated with these contracts are included within gains and losses on risk management contracts on the consolidated statements of income (the "statements of income"). Had these contracts been recognized within operating expenses, ARC’s operating expenses would have been increased by $0.07 per boe for the three months ended December 31, 2015 (increased $0.03 per boe for the year ended December 31, 2015) as a result of a realized loss of $0.8 million during the period (realized loss of $1.1 million for the year ended December 31, 2015).
Exhibit 13
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Transportation expenses were $2.19 per boe during the fourth quarter of 2015 ($2.33 per boe for the year ended December 31, 2015) as compared to $2.51 per boe in the fourth quarter of 2014 ($2.23 per boe for the year ended December 31, 2014). Due to reduced trucking costs at the Parkland/Tower area, which became pipeline-connected for its crude oil volumes over the course of 2015, transportation per boe was 13 per cent lower for the fourth quarter of 2015 compared to 2014. The increase in transportation charges for the year ended December 31, 2015 relative to the same period in 2014 is primarily related to transportation arrangements for new production at Sunrise as well as ARC having to secure supplementary takeaway capacity in the second quarter of 2015 due to maintenance and turnaround activity at a third-party facility.
Exhibit 14
G&A Expenses and Share-Based Compensation
G&A, prior to share-based compensation expense and net of capitalized G&A and overhead recoveries on operated properties, decreased by nine per cent to $13.4 million in the fourth quarter of 2015 from $14.8 million in the fourth quarter of 2014. While G&A expenses before the impact of capitalized G&A and overhead recoveries decreased by 15 per cent from the fourth quarter of 2014 to the fourth quarter of 2015, capitalized G&A and overhead recoveries decreased by 21 per cent during the same period. The reduction in G&A prior to capitalized G&A and overhead recoveries was primarily the result of a significant reduction in cash bonus payments and other discretionary G&A spending in the last half of 2015 relative to 2014. The reduction in capitalized G&A is related to reduced capital spending in the fourth quarter compared to the same period in 2014.
For the year ended December 31, 2015, ARC's G&A prior to share-based compensation expense and net of capitalized G&A and overhead recoveries on operated properties was $61.7 million, a $2.7 million increase from the same period in 2014. The increase reflects decreased capitalized G&A and overhead recoveries from partners associated with lower capital spending, partially offset by lower compensation and bonus expenses.
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Table 17 is a breakdown of G&A and share-based compensation expenses:
Table 17
Three Months Ended | Twelve Months Ended | |||||||||||
December 31 | December 31 | |||||||||||
G&A and Share-Based Compensation | 2015 | 2014 | % Change | 2015 | 2014 | % Change | ||||||
($ millions, except per boe) | ||||||||||||
G&A expenses (1) | 23.1 | 27.1 | (15 | ) | 98.5 | 107.1 | (8 | ) | ||||
Capitalized G&A and overhead recoveries | (9.7 | ) | (12.3 | ) | (21 | ) | (36.8 | ) | (48.1 | ) | (23 | ) |
G&A expenses before share-based compensation plans | 13.4 | 14.8 | (9 | ) | 61.7 | 59.0 | 5 | |||||
G&A – share-based compensation plans (2) | 0.6 | 11.2 | (95 | ) | 6.9 | 25.3 | (73 | ) | ||||
Total G&A and share-based compensation expenses | 14.0 | 26.0 | (46 | ) | 68.6 | 84.3 | (19 | ) | ||||
Total G&A and share-based compensation expenses per boe | 1.28 | 2.40 | (47 | ) | 1.65 | 2.06 | (20 | ) |
(1) | Includes expenses recognized under the DSU Plan. |
(2) | Comprises expenses recognized under the RSU and PSU, Share Option and LTRSA Plans. |
Exhibit 15
Share-Based Compensation Plans – Restricted Share Unit and Performance Share Unit Plan, Share Option Plan, Deferred Share Unit Plan, and Long-term Restricted Share Award Plan
Restricted Share Unit and Performance Share Unit Plan
The RSU and PSU Plan is designed to offer each eligible employee and officer (the “plan participants”) cash compensation in relation to the underlying value of a specified number of share units. The RSU and PSU Plan consists of RSUs for which the number of units is fixed and will vest over a period of three years and PSUs for which the number of units is variable and will vest at the end of three years.
Upon vesting, the plan participant is entitled to receive a cash payment based on the underlying value of the share units plus accrued dividends. The cash compensation issued upon vesting of the PSUs is dependent upon the total return performance of ARC compared to its peers. Total return is calculated as a sum of the change in the market price of the common shares in the period plus the amount of dividends in the period. A performance multiplier is applied to the PSUs based on the percentile rank of ARC’s total shareholder return compared to its peers. The performance multiplier ranges from zero if ARC’s performance ranks in the bottom quartile, to two for top quartile performance.
ARC recorded a G&A recovery of $0.5 million during the fourth quarter of 2015 in accordance with the RSU and PSU Plan, as compared to an expense of $10.4 million during the fourth quarter of 2014. For the year ended December 31, 2015, ARC recorded an expense in G&A related to the RSU and PSU Plan of $2.6 million, a decrease of $20 million or
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88 per cent from the year ended December 31, 2014. ARC recognized a decrease in compensation charges for the fourth quarter of 2015 as compared to the fourth quarter of 2014 due to a reduction to the valuation of awards at December 31, 2015 as ARC's share price decreased from $25.16 per share outstanding at December 31, 2014 to $16.70 at December 31, 2015.
During the year ended December 31, 2015, ARC made cash payments of $25.3 million in respect of the RSU and PSU Plan ($39.4 million for the year ended December 31, 2014). Of these payments, $19.5 million were in respect of amounts recorded to G&A expenses ($28.9 million for the year ended December 31, 2014) and $5.8 million were in respect of amounts recorded to operating expenses and capitalized as PP&E and E&E assets ($10.5 million for the year ended December 31, 2014). These amounts were accrued in prior periods.
Table 18 shows the changes to the RSU and PSU Plan during 2015:
Table 18
RSU and PSU Plan (number of units, thousands) | RSUs | PSUs (1) | Total RSUs and PSUs |
Balance, December 31, 2014 | 625 | 1,513 | 2,138 |
Granted | 464 | 702 | 1,166 |
Distributed | (294) | (493) | (787) |
Forfeited | (65) | (145) | (210) |
Balance, December 31, 2015 | 730 | 1,577 | 2,307 |
(1) | Based on underlying units before any effect of the performance multiplier. |
The liability associated with the RSUs and PSUs granted is recognized in the statements of income over the vesting period while being adjusted each period for changes in the underlying share price, accrued dividends and the number of PSUs expected to be issued on vesting. In periods where substantial share price fluctuation occurs, ARC’s G&A expenses are subject to greater volatility.
Due to the variability in the future payments under the plan, ARC estimates that between $12.6 million and $68 million will be paid out in 2016 through 2018 based on the current share price, accrued dividends, and ARC’s market performance relative to its peers. Table 19 is a summary of the range of future expected payments under the RSU and PSU Plan based on variability of the performance multiplier and units outstanding under the RSU and PSU Plan as at December 31, 2015:
Table 19
Value of RSU and PSU Plan as at | ||||||
December 31, 2015 | Performance multiplier | |||||
(units thousands and $ millions, except per share) | — | 1.0 | 2.0 | |||
Estimated units to vest | ||||||
RSUs | 754 | 754 | 754 | |||
PSUs | — | 1,659 | 3,318 | |||
Total units (1) | 754 | 2,413 | 4,072 | |||
Share price (2) | 16.70 | 16.70 | 16.70 | |||
Value of RSU and PSU Plan upon vesting | 12.6 | 40.3 | 68.0 | |||
2016 | 5.9 | 14.8 | 23.7 | |||
2017 | 4.2 | 11.9 | 19.5 | |||
2018 | 2.5 | 13.6 | 24.8 |
(1) | Includes additional estimated units to be issued under the RSU and PSU Plan for dividends accrued to date. |
(2) | Per share outstanding. Values will fluctuate over the vesting period based on the volatility of the underlying share price. Assumes a future share price of $16.70, which is based on the closing share price at December 31, 2015. |
Share Option Plan
Share options are granted to employees and consultants of ARC, vesting evenly on the fourth and fifth anniversaries of their respective grant dates, and have a maximum term of seven years. The option holder has the right to exercise the options at the original exercise price or at a reduced exercise price, equal to the exercise price at grant date less all dividends paid subsequent to the grant date and prior to the exercise date. On June 24, 2015, ARC granted 998,545 options to officers and certain employees at ARC.
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At December 31, 2015, ARC had 3.2 million share options outstanding under this plan, representing less than one per cent of outstanding shares, with a weighted average exercise price of $21.95 per share. At December 31, 2015, approximately 0.2 million share options were exercisable with a weighted average exercise price of $21.41 per share. Compensation expense of $0.9 million has been recorded during the fourth quarter of 2015 ($3.4 million for the year ended December 31, 2015) compared to $0.8 million for the fourth quarter of 2014 ($2.7 million for the year ended December 31, 2014), and is included within G&A expenses.
Deferred Share Unit Plan
ARC has a DSU Plan for its non-employee directors under which each director receives a minimum of 60 per cent of their total annual remuneration in the form of DSUs. Each DSU fully vests on the date of grant but is settled in cash only when the director has ceased to be a member of the Board. For the three and twelve months ended December 31, 2015, a G&A expense of $0.1 million and a G&A recovery of $0.3 million were recorded in relation to the DSU Plan (G&A recovery of $0.5 million and a G&A expense of $0.8 million in 2014), respectively.
Long-term Restricted Share Award Plan
On April 30, 2015, at its Annual and Special Meeting of Shareholders, ARC shareholders approved a new Long-term Restricted Share Award ("LTRSA") Plan to award shares of ARC to qualifying officers and employees. With a 10 year term and vesting evenly on the eighth, ninth and tenth anniversary of their respective grant dates, the LTRSA is intended to further align participant compensation with the interests of ARC and its shareholders over the long-term.
LTRSA grants consist of restricted common shares that are awarded at the date of grant and a cash payment made equal to the estimated personal tax obligation associated with the total award. The restricted shares issued on the grant date of the award are held in trust until the vesting conditions have been met.
While in trust, the restricted shares earn dividends which are reinvested into ARC common shares via the stock dividend program. These common shares issued through the stock dividend program are also held in trust until vested. Each LTRSA vests evenly on the eighth, ninth, and tenth anniversaries of their respective grant dates. Restricted shares and any accrued dividends that are subject to forfeiture will be redeemed and cancelled by ARC.
Compensation expense associated with the cash payment is recognized at the fair value on the grant date, while expense associated with the restricted common shares is estimated as the fair value of the award equal to the previous five-day weighted average trading price of ARC shares on the grant date and is recognized over the vesting period.
At December 31, 2015, ARC had 93 thousand restricted shares outstanding under this plan. For the three and twelve months ended December 31, 2015, G&A expenses have been recorded of $nil and $0.7 million relating to the cash payment under the LTRSA Plan ($nil for the three and twelve months ended December 31, 2014), respectively.
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Interest and Financing Charges
Interest and financing charges increased three per cent to $13.3 million in the fourth quarter of 2015 from $12.9 million in the fourth quarter of 2014. For the year ended December 31, 2015, interest and financing charges were $51 million as compared to $47.3 million in 2014, an increase of eight per cent. The increase in interest charges primarily reflects the increased value of the US dollar relative to the Canadian dollar in 2015 as compared to 2014 as ARC's debt and related interest obligations are primarily held in US dollars.
At December 31, 2015, ARC had $1.1 billion of long-term debt outstanding, including a current portion of $57.9 million that is due for repayment within the next 12 months. ARC's debt balance is fixed at a weighted average interest rate of 4.43 per cent. Approximately 96 per cent (US$772.1 million) of ARC’s debt outstanding is denominated in US dollars.
Exhibit 16
Foreign Exchange Gains and Losses
ARC recorded a foreign exchange loss of $33.9 million in the fourth quarter of 2015 compared to a loss of $32.3 million in the fourth quarter of 2014. The loss is primarily attributed to the unrealized loss associated with the revaluation of ARC’s US dollar denominated debt outstanding from the period of September 30, 2015 to December 31, 2015 and reflects the change in value of the US dollar relative to the Canadian dollar from $1.34 to $1.38.
For the year ended December 31, 2015, ARC recorded a foreign exchange loss of $177.8 million compared to a loss of $73.7 million for the same period in the prior year. During the year ended December 31, 2014, the value of the US dollar relative to the Canadian dollar increased $0.10 from $1.06 at December 31, 2013 to $1.16 at December 31, 2014. During the year ended December 31, 2015, the value of the US dollar relative to the Canadian dollar increased $0.22 from $1.16 at December 31, 2014 to $1.38 at December 31, 2015, resulting in an increased unrealized loss on the revaluation of ARC's US dollar denominated debt.
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Table 20 shows the various components of foreign exchange gains and losses:
Table 20
Three Months Ended | Twelve Months Ended | |||||||||
December 31 | December 31 | |||||||||
Foreign Exchange Gains and Losses ($ millions) | 2015 | 2014 | % Change | 2015 | 2014 | % Change | ||||
Unrealized loss on US denominated debt | (34.9 | ) | (32.7 | ) | 7 | (178.5 | ) | (73.8 | ) | 142 |
Realized gain on US denominated transactions | 1.0 | 0.4 | 150 | 0.7 | 0.1 | 600 | ||||
Total foreign exchange loss | (33.9 | ) | (32.3 | ) | 5 | (177.8 | ) | (73.7 | ) | 141 |
Taxes
ARC recorded a current income tax recovery of $3 million in the fourth quarter of 2015 ($9 million recovery for the year ended December 31, 2015) compared to $6.3 million expense during the fourth quarter of 2014 ($70.3 million expense for the year ended December 31, 2014). The reduction in current taxes for both the fourth quarter and the year ended December 31, 2015 reflects lower annual taxable income for 2015 related to decreased commodity prices.
During the fourth quarter of 2015, a deferred income tax expense of $3.2 million was recorded ($6.8 million recovery for the year ended December 31, 2015) compared to an expense of $23.5 million in the fourth quarter of 2014 ($59.1 million expense for the year ended December 31, 2014). For both the quarter and year ended December 31, 2015 as compared to the quarter and year ended December 31, 2014, ARC’s decrease in deferred tax expense primarily relates to impairment charges recorded in the third and fourth quarters of 2015 which reduced the book basis of ARC's assets relative to their tax basis and a decrease in unrealized gains recorded on risk management contracts, slightly offset by a net decrease in the asset retirement obligation and an increase to the deferred tax rate as a result of the Alberta corporate tax rate increasing from 10 per cent to 12 per cent effective July 1, 2015.
The income tax pools (detailed in Table 21) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.
Table 21
Income Tax Pool Type ($ millions) | December 31, 2015 | Annual Deductibility | ||
Canadian oil and gas property expense | 595.2 | 10% declining balance | ||
Canadian development expense | 877.1 | 30% declining balance | ||
Canadian exploration expense | — | 100 | % | |
Undepreciated capital cost | 791.4 | Primarily 25% declining balance | ||
Other | 21.8 | Various rates, 7% declining balance to 20% | ||
Total federal tax pools | 2,285.5 | |||
Additional Alberta tax pools | 8.6 | Various rates, 25% declining balance to 100% |
DD&A Expense and Impairment Charges
ARC records DD&A expense on its PP&E over the individual useful lives of the assets employing the unit of production method using proved plus probable reserves and associated estimated future development capital required for its crude oil and natural gas assets, and a straight-line method for its corporate administrative assets. Assets in the E&E phase are not amortized. For the three and twelve months ended December 31, 2015, ARC recorded DD&A expense prior to any impairment of $131.7 million and $595.8 million as compared to $176.4 million and $655.5 million for the three and twelve months ended December 31, 2014. The decrease in DD&A expense for the three months ended December 31, 2015 to $12.01 per boe compared to $16.25 per boe for the fourth quarter of 2014, as well as the decrease for the year ended December 31, 2015 to $14.30 per boe compared to $15.98 per boe for the same period of the prior year, reflects the effect of reduced costs of finding and development of reserves.
Impairment is recognized when the carrying value of an asset or group of assets exceeds its recoverable amount, defined as the higher of its value in use or fair value less costs of disposal. Any asset impairment that is recorded is recoverable to its original value less any associated DD&A expense should there be indicators that the recoverable amount of the asset has increased in value since the time of recording the initial impairment. ARC conducted tests of impairment in 2015 on all of its CGUs as a result of decreases in the outlook of future commodity prices compared to those at December
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31, 2014 as well as, in some CGUs, negative technical reserve revisions in areas with little capital development activity in the current year and decreased fair values of undeveloped land.
For the three months ended December 31, 2015, impairment charges of $131.3 million ($103 million for the three months ended December 31, 2014) were recognized. The impairment charges recorded for the three months ended December 31, 2015 included impairment charges of $80 million due to a decline in expected future commodity prices and $51.3 million in relation to the disposition of non-core assets located in the Southeast Saskatchewan & Manitoba CGU. For the year ended December 31, 2015, impairment charges of $469.6 million ($103 million for the year ended December 31, 2014) were recognized on its Northern Alberta, Pembina, Redwater, Southern Alberta & Southwest Saskatchewan, and Southeast Saskatchewan & Manitoba CGUs. The impairment charges included $400 million due to a decline in expected future commodity prices and negative technical reserve revisions in some CGUs and $69.6 million in relation to the disposition of non-core assets located in the Southern Alberta & Southwest Saskatchewan and Southeast Saskatchewan & Manitoba CGUs.
The results of the impairment tests conducted during the year ended December 31, 2015 are sensitive to changes in any of the key Management judgments and estimates inherent in the calculations, such as a revision in reserves or resources, a change in forecast commodity prices, expected royalties, required future development expenditures or expected future production costs, which could decrease or increase the recoverable amounts of assets and result in additional impairment charges or recovery of impairment charges. For further information regarding the impairment charges for the year ended December 31, 2015, refer to Note 11 "Impairment" in the financial statements.
A breakdown of DD&A expense and impairment charges is summarized in Table 22:
Table 22
Three Months Ended | Twelve Months Ended | |||||||||||
December 31 | December 31 | |||||||||||
DD&A Expense and Impairment Charges ($ millions, except per boe amounts) | 2015 | 2014 | % Change | 2015 | 2014 | % Change | ||||||
Depletion of oil and gas assets | 130.3 | 174.7 | (25 | ) | 589.7 | 649.2 | (9 | ) | ||||
Depreciation of administrative assets | 1.4 | 1.7 | (18 | ) | 6.1 | 6.3 | (3 | ) | ||||
Impairment charges | 131.3 | 103.0 | 27 | 469.6 | 103.0 | 356 | ||||||
Total DD&A expense and impairment charges | 263.0 | 279.4 | (6 | ) | 1,065.4 | 758.5 | 40 | |||||
DD&A rate before impairment per boe | 12.01 | 16.25 | (26 | ) | 14.30 | 15.98 | (11 | ) | ||||
DD&A and impairment rate per boe | 23.97 | 25.74 | (7 | ) | 25.57 | 18.49 | 38 |
During the three and twelve months ended December 31, 2015, ARC recorded impairment charges on E&E assets of $nil and $46.9 million, respectively. Impairment of E&E assets are presented as part of E&E expenses in the statements of income.
Capital Expenditures, Acquisitions and Dispositions
Capital expenditures before acquisitions, dispositions or purchases of undeveloped land totaled $149.5 million in the fourth quarter of 2015 as compared to $249.3 million during the fourth quarter of 2014. This total includes development and production additions to PP&E of $137.4 million and additions to E&E assets of $12.1 million. PP&E expenditures include additions to oil and gas development and production assets and administrative assets. E&E expenditures include asset additions in areas that have been determined by Management to be in the E&E stage.
At the end of the fourth quarter of 2015, ARC divested of certain non-core crude oil assets located in Manitoba. The divested properties had production of approximately 1,300 boe per day, representing less than one per cent of ARC's 2015 proved plus probable oil and gas reserves.
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A breakdown of capital expenditures, acquisitions and dispositions is shown in Table 23 and 23a:
Table 23
Three Months Ended December 31 | ||||||||||||||
2015 | 2014 | |||||||||||||
Capital Expenditures ($ millions) | E&E | PP&E | Total | E&E | PP&E | Total | % Change | |||||||
Geological and geophysical | 0.2 | 2.3 | 2.5 | — | 4.7 | 4.7 | (47 | ) | ||||||
Drilling and completions | 11.1 | 97.4 | 108.5 | 2.5 | 161.9 | 164.4 | (34 | ) | ||||||
Plant and facilities | 0.8 | 36.5 | 37.3 | 1.2 | 77.0 | 78.2 | (52 | ) | ||||||
Administrative assets | — | 1.2 | 1.2 | — | 2.0 | 2.0 | (40 | ) | ||||||
Total capital expenditures | 12.1 | 137.4 | 149.5 | 3.7 | 245.6 | 249.3 | (40 | ) | ||||||
Undeveloped land | 1.5 | 3.1 | 4.6 | 0.6 | 17.4 | 18.0 | (74 | ) | ||||||
Total capital expenditures including undeveloped land purchases | 13.6 | 140.5 | 154.1 | 4.3 | 263.0 | 267.3 | (42 | ) | ||||||
Acquisitions (1) | — | 0.3 | 0.3 | — | — | — | — | |||||||
Dispositions (2) | — | (42.2 | ) | (42.2 | ) | — | (2.4 | ) | (2.4 | ) | 1,658 | |||
Total capital expenditures, land purchases and net dispositions | 13.6 | 98.6 | 112.2 | 4.3 | 260.6 | 264.9 | (58 | ) |
(1) | Excludes $0.9 million of non-cash petroleum and natural gas property transactions in the fourth quarter of 2015 ($4 million in the fourth quarter of 2014). |
(2) | Represents proceeds and adjustments to proceeds from divestitures. |
For the year ended December 31, 2015, capital expenditures before property acquisitions, dispositions or purchases of undeveloped land totaled $541.6 million as compared to $945.5 million during the same period of 2014. This total includes development and production additions to PP&E of $509.2 million and additions to E&E assets of $32.4 million.
Table 23a
Twelve Months Ended December 31 | ||||||||||||||
2015 | 2014 | |||||||||||||
Capital Expenditures ($ millions) | E&E | PP&E | Total | E&E | PP&E | Total | % Change | |||||||
Geological and geophysical | 5.3 | 10.6 | 15.9 | 1.4 | 16.2 | 17.6 | (10 | ) | ||||||
Drilling and completions | 26.0 | 335.2 | 361.2 | 30.8 | 629.2 | 660.0 | (45 | ) | ||||||
Plant and facilities | 1.1 | 160.9 | 162.0 | 15.8 | 245.6 | 261.4 | (38 | ) | ||||||
Administrative assets | — | 2.5 | 2.5 | — | 6.5 | 6.5 | (62 | ) | ||||||
Total capital expenditures | 32.4 | 509.2 | 541.6 | 48.0 | 897.5 | 945.5 | (43 | ) | ||||||
Undeveloped land | 1.5 | 5.2 | 6.7 | 1.4 | 60.9 | 62.3 | (89 | ) | ||||||
Total capital expenditures including undeveloped land purchases | 33.9 | 514.4 | 548.3 | 49.4 | 958.4 | 1,007.8 | (46 | ) | ||||||
Acquisitions (1) | 14.1 | 0.3 | 14.4 | 1.8 | 71.7 | 73.5 | (80 | ) | ||||||
Dispositions (2) | (7.6 | ) | (81.2 | ) | (88.8 | ) | (1.8 | ) | (37.5 | ) | (39.3 | ) | 126 | |
Total capital expenditures, land purchases and net dispositions | 40.4 | 433.5 | 473.9 | 49.4 | 992.6 | 1,042.0 | (55 | ) |
(1) | Excludes $29.6 million of non-cash petroleum and natural gas property transactions in the year ended December 31, 2015 ($5.9 million in the year ended December 31, 2014). |
(2) | Represents proceeds and adjustments to proceeds from divestitures. |
During the year ended December 31, 2015, ARC has divested of certain non-core assets located in South Central Alberta, Southwestern Saskatchewan and Manitoba. In aggregate, the divested properties had associated production volumes of approximately 4,900 boe per day, which resulted in an annual volume impact of approximately 3,000 boe per day (approximately 40 per cent crude oil and liquids at time of divestments).
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Asset Retirement Obligations and Reclamation Fund
At December 31, 2015, ARC has recorded ARO of $573.2 million ($616.1 million at December 31, 2014) for the future abandonment and reclamation of ARC’s properties. The estimated ARO includes assumptions in respect of actual costs to abandon wells or reclaim the property, the time frame in which such costs will be incurred, as well as annual inflation factors in order to calculate the undiscounted total future liability. The future liability has been discounted at a liability-specific risk-free interest rate of 2.2 per cent (2.3 per cent at December 31, 2014).
Accretion charges of $3.3 million and $13.4 million for the three and twelve months ended December 31, 2015 ($3.7 million and $14.9 million for 2014), respectively, have been recognized in the statements of income to reflect the increase in ARO associated with the passage of time. Actual spending under ARC’s abandonment and reclamation program for the three and twelve months ended December 31, 2015 was $4.2 million and $12.3 million ($8.7 million and $23 million for 2014), respectively. For the three and twelve months ended December 31, 2015, divestments related to certain non-core assets decreased ARO by $17 million and $81.7 million ($9.5 million and $38 million for 2014), respectively.
In 2005, ARC established a restricted reclamation fund to finance obligations specifically associated with its Redwater property. Minimum contributions to this fund will be approximately $60.8 million in total over the next 40 years. The balance of this fund totaled $34.3 million at December 31, 2015, compared to $35.2 million at December 31, 2014. Under the terms of ARC’s investment policy, cash in the reclamation fund can only be invested in certain securities and require a minimum credit rating for investments of A or higher.
Environmental stewardship is a core value at ARC and abandonment and reclamation activities continue to be made in a prudent, responsible manner with the oversight of the Health, Safety and Environment Committee of the Board. Ongoing abandonment expenditures for all of ARC’s assets are funded entirely out of cash flow from operating activities.
Capitalization, Financial Resources and Liquidity
A breakdown of ARC’s capital structure as at December 31, 2015 and 2014 is outlined in Table 24:
Table 24
Capital Structure and Liquidity ($ millions, except per cent and ratio amounts) | December 31, 2015 | December 31, 2014 | ||
Long-term debt (1) | 1,114.3 | 1,074.8 | ||
Working capital deficit (surplus) (2) | (129.2 | ) | 181.1 | |
Net debt obligations (3) | 985.1 | 1,255.9 | ||
Market value of common shares (4) | 5,796.6 | 8,036.1 | ||
Total capitalization (3) | 6,781.7 | 9,292.0 | ||
Net debt as a percentage of total capitalization | 14.5 | 13.5 | ||
Net debt to annualized funds from operations (3) | 1.3 | 1.1 |
(1) | Includes a current portion of long-term debt of $57.9 million at December 31, 2015 and $49.5 million at December 31, 2014. |
(2) | Working capital surplus or deficit is calculated as current assets less current liabilities as they appear on the consolidated balance sheets (the "balance sheets"), and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale and ARO contained within liabilities associated with assets held for sale, as well as the current portion of long-term debt and current portion of ARO. |
(3) | Refer to the section entitled "Additional GAAP Measures” contained within this MD&A. |
(4) | Calculated using the total common shares outstanding at December 31, 2015 multiplied by the closing share price of $16.70 at December 31, 2015 (closing share price of $25.16 at December 31, 2014). |
At December 31, 2015, ARC had total available credit facilities of approximately $2.4 billion with debt of $1.1 billion currently outstanding. ARC’s long-term debt balance includes a current portion of $57.9 million at December 31, 2015 ($49.5 million at December 31, 2014), reflecting principal payments that are due to be paid within the next 12 months. ARC intends to finance these obligations by using cash on hand or drawing on its syndicated credit facility at the time the payments are due.
On October 26, 2015, ARC extended its syndicated revolving credit facility for one additional year until November 6, 2019 at existing terms.
In January 2015, ARC issued 17.9 million common shares for aggregate gross proceeds of $402.7 million (net proceeds of $386.1 million) on a bought deal basis. The proceeds from this offering were used to temporarily reduce bank indebtedness, increase working capital and to fund ongoing capital expenditure programs.
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ARC’s debt agreements contain a number of covenants, all of which were met as at December 31, 2015. These agreements are available at www.sedar.com. ARC calculates its covenants four times annually. The major financial covenants are described below:
Table 25
Covenant description | Estimated Position at December 31, 2015 (1) | |
Long-term debt and letters of credit not to exceed three and a quarter times trailing twelve month net income before non-cash items, income taxes and interest expense | 1.4 times | |
Long-term debt, letters of credit, and subordinated debt not to exceed four times trailing twelve month net income before non-cash items, income taxes and interest expense | 1.4 times | |
Long-term debt and letters of credit not to exceed 50 per cent of the book value of shareholders’ equity and long-term debt, letters of credit and subordinated debt | 30 | % |
(1) | Estimated position, subject to final approval. |
ARC intends to keep its net debt to less than two times annualized funds from operations during specific periods with a long-term strategy to keep its net debt balance to a ratio of between one and 1.5 times annualized funds from operations and less than 20 per cent of total capitalization. This strategy has resulted in manageable debt levels to date and has positioned ARC to remain well within its debt covenants. To respond to current commodity pricing levels, ARC has reduced its planned 2016 capital expenditure program to $390 million. Additionally, ARC has decided to reduce its dividend to $0.05 per share outstanding per month.
Exhibit 17
(1) | Refer to the section entitled "Additional GAAP Measures” contained within this MD&A. |
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ARC typically uses three markets to raise capital: equity, bank debt and long-term notes. Long-term notes are issued to large institutional investors normally with an average term of five to 12 years. The cost of this debt is based upon two factors: the current rate of long-term government bonds and ARC’s credit spread. ARC’s weighted average interest rate on its outstanding long-term notes is currently 4.43 per cent.
Exhibit 18
Table 26
Cash Inflows | 2015 | 2014 | 2013 | 2012 | 2011 | |||||
Funds from operations (1) | 773.4 | 1,124.0 | 861.8 | 719.8 | 844.3 | |||||
DRIP & SDP | 195.5 | 151.0 | 130.1 | 116.3 | 105.8 | |||||
Equity issuance (net proceeds) | 386.1 | — | — | 330.7 | — | |||||
Dispositions (2) | 88.8 | 39.3 | 89.8 | 4.1 | 168.4 | |||||
Cash Outflows | ||||||||||
Dividends declared | 410.5 | 380.2 | 374.0 | 357.4 | 344.0 | |||||
Capital expenditures (3) | 547.9 | 1,007.6 | 874.2 | 607.7 | 728.1 | |||||
Acquisitions (2) | 14.4 | 73.5 | 36.4 | 36.5 | 57.1 |
(1) | Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. |
(2) | Excludes non-cash property transactions. |
(3) | Excludes capital expenditures attributable to non-cash share options and asset retirement expenditures. |
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Shareholders’ Equity
At December 31, 2015, there were 347.1 million shares outstanding, an increase of 27.7 million shares compared to December 31, 2014. During the first quarter of 2015, ARC issued 17.9 million shares for aggregate gross proceeds of $402.7 million. The remaining 9.8 million shares issued are attributable to those issued to participants in the DRIP and SDP.
At December 31, 2015, ARC had 3.2 million share options outstanding under its Share Option Plan, representing less than one per cent of outstanding shares, with a weighted average exercise price of $21.95 per share. These options vest in equal parts on the fourth and fifth anniversaries of the grant date. At December 31, 2015, approximately 0.2 million share options were exercisable with a weighted average exercise price of $21.41 per share.
At December 31, 2015, ARC had 93 thousand restricted shares outstanding under its Long-term Restricted Share Award Plan. These awards vest evenly on the eighth, ninth and tenth anniversaries of the grant date. For more information on the restricted shares outstanding and held in trust under ARC's LTRSA Plan, refer to the section entitled "Long-term Restricted Share Award Plan” contained within this MD&A.
Dividends
In the fourth quarter of 2015, ARC declared dividends totaling $103.8 million ($0.30 per share outstanding) compared to $95.7 million ($0.30 per share outstanding) during the fourth quarter of 2014. During the year ended December 31, 2015, ARC declared dividends totaling $410.5 million ($1.20 per share outstanding) compared to $380.2 million ($1.20 per share outstanding) during the year ended December 31, 2014.
As a dividend-paying corporation, ARC declares monthly dividends to its shareholders. ARC continually assesses dividend levels in light of commodity prices, capital expenditure programs, and production volumes to ensure that dividends are in line with the long-term strategy and objectives of ARC as per the following guidelines:
• | To maintain a dividend policy that, in normal times, in the opinion of Management and the Board, is sustainable after factoring in the impact of current commodity prices on funds from operations. ARC’s objective is to normalize the effect of volatility of commodity prices rather than to pass that volatility onto shareholders in the form of fluctuating monthly dividends. |
• | To maintain ARC’s financial flexibility, by reviewing ARC’s level of debt to equity and debt to funds from operations. The use of funds from operations and proceeds from equity offerings to fund capital development activities reduces the need to use debt to finance these expenditures. |
ARC is focused on value creation, with the dividend being a key component of its business strategy. As commodity prices have persistently decreased throughout 2015 and into 2016, ARC’s dividend as a percent of funds from operations has increased from an average of 34 per cent in 2014 to an average of 53 per cent in 2015. Based on ARC’s current forecast of its 2016 expected funds from operations, ARC believes that it is prudent to reduce its monthly dividend to $0.05 per share.
Exhibit 19
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The actual amount of future monthly dividends is proposed by Management and is subject to the approval and discretion of the Board. The Board reviews future dividends in conjunction with their review of quarterly financial and operating results. Dividends are taxable to the shareholder irrespective of whether payment is received in cash or shares via the DRIP. In the case of shares issued via the SDP, dividends received are converted to a future capital gain to the recipient. Shareholders should consult their own tax advisors with respect to tax implications of dividends received in cash or via the DRIP or SDP in their particular circumstances.
On January 18, 2016, ARC confirmed that a dividend of $0.10 per common share designated as an eligible dividend will be paid on February 16, 2016 to shareholders of record on January 29, 2016 with an ex-dividend date of January 27, 2016.
Please refer to ARC’s website at www.arcresources.com for details of the estimated monthly dividend amounts and dividend dates for 2016.
Environmental Initiatives Impacting ARC
In the fourth quarter of 2015, the provincial government of Alberta released its Climate Leadership Plan which will impact all consumers and businesses that contribute to carbon emissions in Alberta. This plan includes imposing carbon pricing that is applied across all sectors, starting at $20 per tonne on January 1, 2017 and moving to $30 per tonne on January 1, 2018, the phase-out of coal-fired power generation by 2030, a cap on oil sands emissions production of 100 megatonnes, and a 45 per cent reduction in methane emissions by the oil and gas sector by 2025. ARC expects the Climate Leadership Plan to increase the cost of operating its properties located in Alberta and is currently evaluating the expected impact of this plan on its results of operations.
Contractual Obligations and Commitments
Table 27 discloses ARC's contractual obligations and commitments at December 31, 2015 and the associated minimum future payments:
Table 27
Payments Due by Period | ||||||||||
Contractual Obligations and Commitments ($ millions) | 1 Year | 2-3 Years | 4-5 Years | Beyond 5 Years | Total | |||||
Debt repayments (1) | 57.9 | 134.8 | 240.5 | 681.1 | 1,114.3 | |||||
Interest payments (2) | 48.0 | 86.6 | 70.3 | 71.5 | 276.4 | |||||
Reclamation fund contributions (3) | 3.3 | 6.2 | 5.7 | 45.6 | 60.8 | |||||
Purchase commitments | 57.1 | 22.6 | 8.6 | 5.4 | 93.7 | |||||
Transportation commitments | 84.5 | 166.1 | 112.0 | 290.5 | 653.1 | |||||
Operating leases | 15.5 | 29.6 | 27.4 | 45.1 | 117.6 | |||||
Risk management contract premiums (4) | 4.5 | 5.8 | 0.5 | — | 10.8 | |||||
Total contractual obligations and commitments | 270.8 | 451.7 | 465.0 | 1,139.2 | 2,326.7 |
(1) | Long-term and current portion of long-term debt. |
(2) | Fixed interest payments on senior notes. |
(3) | Contribution commitments to a restricted reclamation fund associated with the Redwater property. |
(4) | Fixed premiums to be paid in future periods on certain commodity price risk management contracts. |
In addition to the above risk management contract premiums, ARC has commitments related to its risk management program (see Note 16). As the premiums are related to the underlying risk management contract, they have been recorded at fair market value at December 31, 2015 on the balance sheet as part of risk management contracts.
During the year ended December 31, 2015, ARC increased its transportation commitments by approximately $73.9 million from those presented at December 31, 2014. The increase relates to additional firm natural gas transportation that ARC committed to support the movement of ARC's future natural gas production.
ARC enters into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital expenditures in a future period.
ARC is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material impact on ARC’s financial position or results of operations and therefore Table 27 does not include any commitments for outstanding litigation and claims.
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Off-Balance Sheet Arrangements
ARC has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 27), which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases on the balance sheet as of December 31, 2015.
Related Parties
Interest in Partnership
ARC owns a 99.99% interest in the ARC Resources General Partnership. The other 0.01% of the partnership is owned by 1504793 Alberta Ltd, a 100% owned subsidiary of ARC. ARC’s oil and gas properties are owned and administered by the partnership. ARC is also the sole beneficiary of the Redwater A&R Trust, which administers the reclamation fund on ARC’s behalf.
Key Management Personnel Compensation
ARC has determined that the key management personnel of ARC consists of its officers and directors. Short-term benefits are comprised of salaries and directors' fees, annual bonuses, and other benefits. In addition, the Company provides share-based compensation to its key management personnel under the RSU and PSU, DSU, LTRSA and Share Option Plans. The compensation expense included in G&A expenses relating to key management personnel for the year is as follows:
Table 28
Year Ended December 31, 2015 | Year Ended December 31, 2014 | ||||
Short-term benefits | 7.2 | 8.0 | |||
Share-based compensation | 1.6 | 15.6 | |||
Total key management personnel compensation | 8.8 | 23.6 |
Critical Accounting Estimates
ARC has continuously refined and documented its management and internal reporting systems to ensure that accurate, timely, internal and external information is gathered and disseminated.
ARC’s financial and operating results incorporate certain estimates including:
• | estimated revenues, royalties and operating expenses on production as at a specific reporting date but for which actual revenues and costs have not yet been received; |
• | estimated capital expenditures on projects that are in progress; |
• | estimated DD&A charges that are based on estimates of oil and gas reserves that ARC expects to recover in the future; |
• | estimated fair values of financial instruments that are subject to fluctuation depending upon the underlying commodity prices, foreign exchange rates and interest rates, volatility curves and the risk of non-performance; |
• | estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; |
• | estimated future recoverable value of PP&E, E&E and goodwill and any associated impairment charges or recoveries; and |
• | estimated compensation expense under ARC’s share-based compensation plans including the PSUs awarded under the RSU and PSU Plan that is based on an adjustment to the final number of PSU awards that eventually vest based on a performance multiplier, the Share Option Plan and the LTRSA Plan. |
ARC has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates. For further information on the determination of certain estimates inherent
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in the financial statements, refer to Note 5 “Management Judgments and Estimation Uncertainty” and Note 11 "Impairment" in the financial statements.
ARC’s leadership team’s mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with ARC’s environmental, health and safety policies.
ASSESSMENT OF BUSINESS RISKS
The ARC management team is focused on long-term strategic planning and has identified the key risks, uncertainties and opportunities associated with ARC’s business that can impact the financial results. They include, but are not limited to:
Volatility of Oil and Natural Gas Prices
ARC’s operational results and financial condition, and therefore the amount of capital expenditures and future dividend payments made to shareholders, are dependent on the prices received for crude oil and natural gas production. Decreasing crude oil and natural gas prices will reduce ARC’s cash flow, impacting ARC’s level of capital expenditures and may result in the shut-in of certain producing properties. Differentials on Canadian crude oil have also shown significant volatility throughout recent years due to pipeline and infrastructure constraints. Any movement in crude oil and natural gas prices will have an effect on ARC’s ability to continue with its capital expenditure program and its ability to pay dividends. Future declines in crude oil and natural gas prices may result in future declines in, or elimination of, any future dividends. Crude oil and natural gas prices are determined by economic and, in some circumstances, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other crude oil and natural gas regions, impact prices. ARC may manage the risk associated with changes in commodity prices by entering into crude oil or natural gas price derivative contracts. If ARC engages in activities to manage its commodity price exposure, it may forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity derivative contracts activities could expose ARC to losses. To the extent that ARC engages in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which it contracts.
Refinancing and Debt Service
ARC currently has a $1 billion financial covenant-based syndicated credit facility with 12 banks. At the request of ARC, the lenders will review the credit facility each year and determine if they will extend for another year. In the event that the facility is not extended before November 6, 2019, indebtedness under the facility will become repayable at that date. There is also a risk that the credit facility will not be renewed for the same amount or on the same terms. Any of these events could affect ARC’s ability to fund ongoing operations and make future dividend payments.
ARC currently has $1,114.3 million of long-term, fixed interest rate debt outstanding which requires principal repayments in 2016 through 2026. ARC intends to fund these principal repayments with existing credit facilities. In the event ARC is unable to fund future principal repayments, it may impact ARC’s ability to fund its ongoing operations and make future dividend payments.
ARC is required to comply with covenants under the credit facility. In the event that ARC does not comply with covenants under the credit facility, ARC’s access to capital could be restricted or repayment could be required. ARC routinely reviews the covenants based on actual and forecast results and has the ability to make changes to its development plans and/or dividend policy to comply with covenants under the credit facility. If ARC becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lender may foreclose on such assets of ARC or sell the working interests.
Access to Capital Markets
ARC's capital expenditures are financed from funds from operations, borrowings, proceeds from property divestments and possible future equity issuances. ARC's ability to issue equity is dependent upon, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry and ARC securities. Further, if revenues or reserves decline ARC may not have access to the capital necessary to undertake or complete future drilling programs.
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Additionally, ARC may issue additional common shares from treasury at prices which may result in a decline in production per common share and reserves per common share.
To the extent that external sources of capital become limited or unavailable or available on onerous terms, ARC's ability to make capital investments and maintain or expand existing assets and reserves may be impaired and ARC's assets, liabilities, business, financial condition, results of operations and dividend payments may be materially or adversely affected as a result.
Retention of Key Personnel
A loss in the key personnel of ARC could delay the completion of certain projects or otherwise have a material adverse effect on the Company. Shareholders are dependent on ARC's management and staff in respect of the administration and management of all manners relating to ARC's assets. Any deterioration of ARC's corporate culture could adversely affect ARC's long-term success.
Operational Matters
The operation of oil and gas wells involves a number of operating and natural hazards that may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to operating subsidiaries of ARC and possible liability to third parties. ARC maintains liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. ARC may become liable for damages arising from such events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities may reduce dividend payments to shareholders.
Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. Approximately nine per cent of ARC’s production is operated by third parties. ARC has limited ability to influence costs on partner operated properties. Operating costs on most properties operated by third parties have increased steadily over recent years. To the extent the operator fails to perform these functions properly, ARC’s revenue from such property may be reduced. Payments from production generally flow through the operator and there is a risk of delayed payment, or non-payment and additional expense in recovering such revenues if the operator becomes insolvent. To mitigate this risk, all significant non-operated production is taken in kind and marketed by ARC. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of ARC to certain properties. A reduction of future dividend payments to shareholders could result under such circumstances.
Reserves and Resources Estimates
The reserves and recovery information contained in ARC’s independent reserves evaluation is only an estimate. Likewise, information contained in ARC's Independent Resources Evaluation for its lands in the northeast British Columbia Montney region, including lands at Pouce Coupe, Alberta, is also only an estimate. The actual production and ultimate reserves and resources from the properties may be greater or less than the estimates prepared by the independent reserves evaluator. The reserves and resources reports have been prepared using certain commodity price assumptions. If lower prices for crude oil, natural gas, condensate and NGLs are realized by ARC and substituted for the price assumptions utilized in those reserves and resources reports, the present value of estimated future net cash flows for ARC’s reserves and resources as well as the amount of ARC’s reserves and resources would be reduced and the reduction could be significant.
Depletion of Reserves and Maintenance of Dividend
ARC’s future crude oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on ARC’s success in exploiting its reserves base and acquiring additional reserves. Without reserves additions through acquisition or development activities, ARC’s reserves and production will decline over time as the oil and natural gas reserves are produced out. There can be no assurance that ARC will make sufficient capital expenditures to maintain production at current levels nor, as a consequence, that the amount of dividends by ARC to shareholders can be maintained at current levels. There can be no assurance that ARC will be successful in developing or acquiring additional reserves on terms that meet ARC’s investment objectives.
Counterparty Risk
ARC assumes customer credit risk associated with oil and gas sales, financial hedging transactions and joint arrangement participants. In the event that ARC’s counterparties default on payments to ARC, cash flows will be impacted and dividend payments to shareholders may be impacted. ARC has established credit policies and controls designed to mitigate the risk of default or non-payment with respect to oil and gas sales, financial hedging transactions and joint arrangement
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participants. A diversified sales customer base is maintained and exposure to individual entities is reviewed on a regular basis.
Variations in Interest Rates and Foreign Exchange Rates
Variations in interest rates could result in an increase in the amount ARC pays to service debt. World oil prices are quoted in US dollars and the price received by Canadian producers is therefore affected by the Canadian/US dollar exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact ARC’s net production revenue. Volatility in interest rates and the Canadian dollar may affect future cash flow from operations and reduce funds available for both dividends and capital expenditures. ARC may initiate certain derivative contracts to attempt to mitigate these risks. To the extent that ARC engages in risk management activities related to foreign exchange rates, it will be subject to credit risk associated with counterparties with which it contracts. An increase in Canadian/US exchange rates may impact future dividend payments to shareholders and the value of ARC’s reserves as determined by independent evaluators.
Changes in Income Tax Legislation
In the future, income tax laws or other laws may be changed or interpreted in a manner that adversely affects ARC or its shareholders. Tax authorities having jurisdiction over ARC or its shareholders may disagree with how ARC calculates its income for tax purposes to the detriment of ARC and its shareholders.
Changes in Government Royalty Legislation
Provincial programs related to the crude oil and natural gas industry may change in a manner that adversely impacts shareholders. ARC currently operates in British Columbia, Alberta and Saskatchewan, all of which have different royalty programs that could be revised at any time. Future amendments to royalty programs in any of ARC’s operating jurisdictions could result in reduced cash flow and reduced dividend payments to shareholders.
In 2016, the provincial government of Alberta announced the key highlights of a proposed Modernized Royalty Framework ("MRF") that will be effective on January 1, 2017. The MRF is discussed in this MD&A under the heading "Royalties." The changes are not expected to have a material impact on ARC's results of operations and ARC will evaluate the impact of the MRF on the Company’s expected results of operations and cash flows as more details are released.
Environmental Concerns and Changes in Environmental Legislation
The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders in respect of ARC or its working interests. Such legislation may be changed to impose higher standards and potentially more costly obligations to ARC. Furthermore, Management believes the federal government appears to favor new programs for environmental laws and regulation, particularly in relation to the reduction of emissions, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which ARC cannot meet. Financial penalties or charges could be incurred as a result of the failure to meet such targets. In particular there is uncertainty regarding the Federal Government’s Regulatory Framework for Air Emissions (“Framework”), as issued under the Canadian Environmental Protection Act.
In the fourth quarter of 2015, the provincial government of Alberta released its Climate Leadership Plan which will impact all consumers and businesses that contribute to carbon emissions in Alberta. The Climate Leadership Plan is discussed in this MD&A under the heading "Environmental Initiatives Impacting ARC."
The use of fracture stimulations has been ongoing safely in an environmentally responsible manner in western Canada for decades. With the increase in the use of fracture stimulations in horizontal wells there is increased communication between the oil and natural gas industry and a wider variety of stakeholders regarding the responsible use of this technology. This increased attention to fracture stimulations may result in increased regulation or changes of law which may make the conduct of ARC’s business more expensive or prevent ARC from conducting its business as currently conducted. ARC focuses on conducting its operations in a safe, responsible and transparent manner in the communities in which its people live and work.
Acquisitions
The price paid for acquisitions is based on engineering and economic estimates of the potential reserves made by independent engineers modified to reflect the technical views of Management. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of crude oil, natural gas, condensate and NGLs, future prices of crude oil, natural gas, condensate and NGLs, and operating costs, future capital expenditures and royalties and other government levies that will be imposed over the producing life of the reserves. Many of these
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factors are subject to change and are beyond the control of the operators of the working interests, Management and ARC. In particular, changes in the prices of and markets for crude oil, natural gas, condensate and NGLs from those anticipated at the time of making such assessments will affect the amount of future dividends and the value of the shares. In addition, all such estimates involve a measure of geological and engineering uncertainty that could result in lower production and reserves than attributed to the working interests. Actual reserves could vary materially from these estimates. Consequently, the reserves acquired may be less than expected, which could adversely impact cash flow and dividends to shareholders.
PROJECT RISKS
ARC manages a variety of small and large projects and plans to continue with the development of several capital projects throughout 2016. Project delays may impact expected revenues from operations. Significant project cost overruns could make a project uneconomic. ARC's ability to execute projects and market oil and natural gas depends upon numerous factors beyond its control, including:
• | availability of processing capacity; |
• | availability and proximity of pipeline capacity; |
• | availability of storage capacity; |
• | supply of and demand for oil and natural gas; |
• | availability of alternative fuel sources; |
• | effects of inclement weather; |
• | availability of drilling and related equipment; |
• | unexpected cost increases; |
• | accidental events; |
• | changes in regulations; and |
• | availability and productivity of skilled labour. |
Because of these factors, ARC could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that ARC produces.
CONTROL ENVIRONMENT
Disclosure Controls and Procedures
As of December 31, 2015, an internal evaluation was carried out of the effectiveness of ARC’s disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Based on that evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that ARC files or submits under the Exchange Act or under Canadian Securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by ARC in the reports that it files or submits under the Exchange Act or under Canadian Securities Legislation is accumulated and communicated to ARC’s Management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.
Internal Control over Financial Reporting
Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of ARC’s internal control over financial reporting as defined
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in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that ARC’s internal control over financial reporting was effective as of December 31, 2015. The effectiveness of ARC’s internal control over financial reporting as of December 31, 2015 has been audited by Deloitte LLP, as reflected in their report for 2015. No changes were made to ARC’s internal control over financial reporting during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.
FINANCIAL REPORTING UPDATE
Future Accounting Policy Changes
In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, which replaces International Accounting Standard ("IAS") 18 Revenue, IAS 11 Construction Contracts, and related interpretations. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 15 will be applied by ARC on January 1, 2018 and the Company is currently evaluating the impact of the standard on ARC's financial statements.
In July 2014, the IASB completed the final elements of IFRS 9 Financial Instruments. The standard supersedes earlier versions of IFRS 9 and completes the IASB’s project to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9, as amended, includes a principle-based approach for classification and measurement of financial assets, a single 'expected loss’ impairment model and a substantially-reformed approach to hedge accounting. The standard will come into effect for annual periods beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 9 will be applied on a retrospective basis by ARC on January 1, 2018 and the Company is currently evaluating the impact of the standard on ARC's financial statements.
In January 2016, the IASB issued IFRS 16 Leases, which replaces IAS 17 Leases. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. IFRS 16 will be applied by ARC on January 1, 2019 and the Company is currently evaluating the impact of the standard on ARC's financial statements.
Non-GAAP Measures
Throughout this MD&A, the company uses the terms operating netback (“netback”) and total return to analyze financial and operating performance. These non-GAAP measures as presented do not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities. Management feels that these non-GAAP measures are key industry benchmarks and measures of performance for ARC and provide investors with information that is commonly used by other oil and gas companies.
Netback
Netback is a common non-GAAP metric used in the oil and gas industry. This measurement assists Management and
investors in evaluating operating results on a per boe basis to better analyze performance on a comparable basis. A calculation of netback is disclosed in Table 16 within this MD&A.
investors in evaluating operating results on a per boe basis to better analyze performance on a comparable basis. A calculation of netback is disclosed in Table 16 within this MD&A.
Total return
Total return is a non-GAAP measure that assists Management and investors in evaluating the Company's performance and rate of return on a per share basis. A calculation of total return is disclosed in Table 1 within this MD&A.
Additional GAAP Measures
All additional GAAP Measures described below do not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities.
Funds from Operations
Funds from operations is defined as net income excluding the impact of non-cash DD&A and impairment charges, accretion of ARO, E&E expense, deferred tax expense and recovery, unrealized gains and losses on risk management contracts, unrealized gains and losses on foreign exchange, gains on disposal of petroleum and natural gas properties, unrealized gains and losses on short-term investments, non-cash lease inducement charges, share-based compensation
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expense, and is further adjusted to include any portion of unrealized gains and losses on risk management contracts settled annually that relate to current period production. Funds from operations per share is calculated as funds from operations divided by the number of weighted average diluted shares. Refer to the reconciliation of funds from operations disclosed in Table 6 within this MD&A and Note 15 "Capital Management" of the financial statements as at and for the years ended December 31, 2015 and 2014. ARC considers funds from operations to be a key measure of operating performance as it demonstrates ARC’s ability to generate the necessary funds to fund future growth through capital investment and to repay debt. Management believes that such a measure provides a better assessment of ARC’s operations on a continuing basis by eliminating certain non-cash charges and charges that are nonrecurring, while respecting that certain risk management contracts that are settled on an annual basis are intended to protect prices on product sales occurring throughout the year. From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income.
Net Debt
Net debt is defined as long-term debt, including the current portion of long-term debt, plus working capital surplus or deficit. Working capital surplus or deficit is calculated as current assets less current liabilities as they appear on the balance sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale, ARO contained within liabilities associated with assets held for sale, the current portion of long-term debt and current portion of ARO. Refer to the reconciliation of net debt disclosed in Table 24 within this MD&A and Note 15 "Capital Management" of the financial statements. Net debt is used by Management as a key measure to assess the Company's liquidity.
Total Capitalization
Total capitalization is defined as total shares outstanding multiplied by the closing share price on the Toronto Stock Exchange plus net debt outstanding. Refer to the reconciliation of total capitalization disclosed in Table 24 within this MD&A and Note 15 "Capital Management" of the financial statements. Total capitalization is used by Management and ARC's investors in analyzing the Company's balance sheet strength and liquidity.
Forward-looking Information and Statements
This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect," "anticipate," "continue," "estimate," "objective," "ongoing," "may," "will," "project," "should," "believe," "plans," "intends," "strategy," and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: ARC’s financial goals under the heading “About ARC Resources Ltd.," ARC’s view of future crude oil, natural gas, condensate and NGLs pricing under the heading “Economic Environment,” ARC’s guidance for 2016 and the re-evaluation of 2016 capital spending under the heading “Annual Guidance and Financial Highlights,” ARC’s risk management plans for 2016 and beyond under the heading “Risk Management,” ARC's view on the impact of the government of Alberta's recently announced Modernized Royalty Framework ("MRF") on ARC's results of operations under the heading "Royalties," ARC’s view as to the estimated future payments under the RSU and PSU Plan under the heading “Share-Based Compensation Plans – Restricted Share Unit and Performance Share Unit Plan, Share Option Plan, Deferred Share Unit Plan, and Long-term Restricted Share Award Plan,” the financing information relating to raising capital under the heading "Capitalization, Financial Resources and Liquidity," ARC's plans in relation to future dividend levels under the heading "Dividends," ARC’s estimates of normal course obligations under the heading “Contractual Obligations and Commitments,” and a number of other matters, including the amount of future asset retirement obligations, future liquidity and financial capacity, future results from operations and operating metrics, future costs, expenses and royalty rates, future interest costs, and future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures.
The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and funds from operations to fund its planned expenditures. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or
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supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third-party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this MD&A and in ARC's Annual Information Form).
The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
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GLOSSARY
The following is a list of abbreviations that may be used in this MD&A:
Measurement
bbl barrel
bbl/d barrels per day
Mbbls thousand barrels
MMbbls million barrels
boe (1) barrels of oil equivalent
boe/d (1) barrels of oil equivalent per day
Mboe (1) thousands of barrels of oil equivalent
MMboe (1) millions of barrels of oil equivalent
Mcf thousand cubic feet
Mcf/d thousand cubic feet per day
MMcf million cubic feet
MMcf/d million cubic feet per day
Bcf billion cubic feet
MMbtu million British Thermal Units
GJ gigajoule
(1) Where applicable in this MD&A natural gas has been converted to boe based on a conversion ratio of six Mcf to one bbl. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the conversion ratio, utilizing a conversion ratio of 6:1 may be misleading as an indication of value.
Financial and Business Environment
ARO asset retirement obligations
CGU cash-generating unit
DD&A depletion, depreciation and amortization
DRIP Dividend Reinvestment Program
DSU Deferred Share Unit
E&E exploration and evaluation
GAAP generally accepted accounting principles
G&A general and administrative
IASB International Accounting Standards Board
IFRS International Financial Reporting Standards
LTRSA Long-term Restricted Share Award
MSW Mixed Sweet Blend
NGLs natural gas liquids
NYMEX New York Mercantile Exchange
PP&E property, plant and equipment
PSU Performance Share Unit
RSU Restricted Share Unit
SDP Stock Dividend Program
WTI West Texas Intermediate
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ANNUAL HISTORICAL REVIEW
For the year ended December 31 | ||||||||||
($ millions, except per share amounts) | 2015 | 2014 | 2013 | 2012 | 2011 | |||||
FINANCIAL | ||||||||||
Sales of crude oil, natural gas, condensate and NGLs | 1,193.7 | 2,107.7 | 1,624.3 | 1,389.4 | 1,438.2 | |||||
Per share, basic | 3.51 | 6.66 | 5.21 | 4.67 | 5.02 | |||||
Per share, diluted | 3.51 | 6.64 | 5.21 | 4.67 | 5.02 | |||||
Funds from operations (1) | 773.4 | 1,124.0 | 861.8 | 719.8 | 844.3 | |||||
Per share, basic | 2.27 | 3.55 | 2.77 | 2.42 | 2.95 | |||||
Per share, diluted | 2.27 | 3.54 | 2.76 | 2.42 | 2.95 | |||||
Net income (loss) and comprehensive income (loss) | (342.6 | ) | 380.8 | 240.7 | 139.2 | 287.0 | ||||
Per share, basic | (1.01 | ) | 1.20 | 0.77 | 0.47 | 1.00 | ||||
Per share, diluted | (1.01 | ) | 1.20 | 0.77 | 0.47 | 1.00 | ||||
Dividends declared | 410.5 | 380.2 | 374.0 | 357.4 | 344.0 | |||||
Per share (2) | 1.20 | 1.20 | 1.20 | 1.20 | 1.20 | |||||
Total assets | 5,932.2 | 6,325.5 | 5,736.0 | 5,627.1 | 5,323.9 | |||||
Total liabilities | 2,543.7 | 2,773.7 | 2,339.9 | 2,230.4 | 2,162.1 | |||||
Net debt outstanding (3) | 985.1 | 1,255.9 | 1,011.5 | 745.6 | 909.7 | |||||
Weighted average shares outstanding | 340.5 | 316.6 | 311.5 | 297.2 | 286.6 | |||||
Weighted average shares outstanding, diluted | 340.5 | 317.2 | 311.9 | 297.2 | 286.6 | |||||
Shares outstanding, end of period | 347.1 | 319.4 | 314.1 | 308.9 | 288.9 | |||||
CAPITAL EXPENDITURES | ||||||||||
Geological and geophysical | 15.9 | 17.6 | 19.2 | 31.8 | 25.9 | |||||
Drilling and completions | 361.2 | 660.0 | 568.4 | 429.8 | 456.5 | |||||
Plant and facilities | 162.0 | 261.4 | 267.7 | 131.6 | 165.1 | |||||
Other | 2.5 | 6.5 | 4.6 | 5.3 | 3.6 | |||||
Total capital expenditures | 541.6 | 945.5 | 859.9 | 598.5 | 651.1 | |||||
Undeveloped land purchased at Crown land sales | 6.7 | 62.3 | 14.3 | 9.5 | 74.9 | |||||
Total capital expenditures including undeveloped land purchases | 548.3 | 1,007.8 | 874.2 | 608.0 | 726.0 | |||||
Acquisitions | 14.4 | 73.5 | 36.4 | 36.5 | 57.1 | |||||
Dispositions | (88.8 | ) | (39.3 | ) | (89.8 | ) | (4.1 | ) | (168.4 | ) |
Total capital expenditures and net acquisitions | 473.9 | 1,042.0 | 820.8 | 640.4 | 614.7 | |||||
OPERATING | ||||||||||
Production | ||||||||||
Crude oil (bbl/d) | 32,762 | 36,525 | 32,784 | 31,454 | 27,158 | |||||
Condensate (bbl/d) | 3,430 | 3,667 | 2,251 | 2,217 | 2,052 | |||||
Natural gas (MMcf/d) | 444.9 | 406.1 | 349.4 | 342.9 | 310.6 | |||||
NGLs (bbl/d) | 3,819 | 4,518 | 2,811 | 2,728 | 2,444 | |||||
Total (boe/d) | 114,167 | 112,387 | 96,087 | 93,546 | 83,416 | |||||
Average realized prices, prior to hedging | ||||||||||
Crude oil ($/bbl) | 53.53 | 90.64 | 88.90 | 82.03 | 89.51 | |||||
Condensate ($/bbl) | 53.84 | 93.81 | 94.13 | 92.63 | 96.07 | |||||
Natural gas ($/Mcf) | 2.88 | 4.76 | 3.45 | 2.62 | 3.83 | |||||
NGLs ($/bbl) | 10.70 | 39.45 | 36.25 | 38.11 | 47.53 | |||||
Oil equivalent ($/boe) | 28.57 | 51.31 | 46.31 | 40.50 | 47.15 | |||||
RESERVES (company gross) (4) | ||||||||||
Proved plus probable reserves | ||||||||||
Crude oil and NGLs (mbbl) | 199,826 | 192,489 | 194,064 | 185,548 | 170,153 | |||||
Natural gas (bcf) | 2,992.1 | 2,881.6 | 2,638.8 | 2,528.6 | 2,413.3 | |||||
Total (mboe) | 686,851 | 672,748 | 633,864 | 606,982 | 572,374 | |||||
TRADING STATISTICS ($, based on intra-day trading) | ||||||||||
High | 25.87 | 33.68 | 29.95 | 26.25 | 28.67 | |||||
Low | 15.39 | 22.70 | 23.12 | 18.36 | 19.40 | |||||
Close | 16.70 | 25.16 | 29.57 | 24.44 | 25.10 | |||||
Average daily volume (thousands) | 1,832 | 1,344 | 1,064 | 1,356 | 1,251 |
(1) | Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. |
(2) | Dividends per share are based on the number of shares outstanding at each dividend record date. |
(3) | Refer to the sections entitled "Capitalization, Financial Resources and Liquidity" and “Additional GAAP Measures” contained within this MD&A. |
(4) | Company gross reserves are the gross interest reserves before deduction of royalties and without including any royalty interests. |
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QUARTERLY HISTORICAL REVIEW
($ millions, except per share amounts) | 2015 | 2014 | ||||||||||||||
FINANCIAL | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||
Sales of crude oil, natural gas, condensate, NGLs and other income | 285.9 | 279.5 | 321.7 | 306.6 | 454.1 | 535.2 | 567.0 | 551.4 | ||||||||
Per share, basic | 0.83 | 0.82 | 0.95 | 0.92 | 1.43 | 1.69 | 1.79 | 1.75 | ||||||||
Per share, diluted | 0.83 | 0.82 | 0.94 | 0.92 | 1.42 | 1.68 | 1.79 | 1.75 | ||||||||
Funds from operations (1) | 200.7 | 174.9 | 206.3 | 191.5 | 251.7 | 284.2 | 295.8 | 292.3 | ||||||||
Per share, basic | 0.58 | 0.51 | 0.61 | 0.57 | 0.79 | 0.90 | 0.94 | 0.93 | ||||||||
Per share, diluted | 0.58 | 0.51 | 0.61 | 0.57 | 0.79 | 0.89 | 0.93 | 0.93 | ||||||||
Net income (loss) | (55.0 | ) | (235.0 | ) | (51.0 | ) | (1.7 | ) | 113.7 | 90.3 | 147.4 | 29.4 | ||||
Per share, basic | (0.16 | ) | (0.69 | ) | (0.15 | ) | (0.01 | ) | 0.36 | 0.28 | 0.47 | 0.09 | ||||
Per share, diluted | (0.16 | ) | (0.69 | ) | (0.15 | ) | (0.01 | ) | 0.36 | 0.28 | 0.47 | 0.09 | ||||
Dividends declared | 103.8 | 103.0 | 102.1 | 101.6 | 95.7 | 95.2 | 94.8 | 94.5 | ||||||||
Per share (2) | 0.30 | 0.30 | 0.30 | 0.30 | 0.30 | 0.30 | 0.30 | 0.30 | ||||||||
Total assets | 5,932.2 | 6,072.4 | 6,346.0 | 6,588.8 | 6,325.5 | 6,095.5 | 5,988.7 | 5,949.5 | ||||||||
Total liabilities | 2,543.7 | 2,578.3 | 2,565.7 | 2,704.2 | 2,773.7 | 2,603.5 | 2,531.1 | 2,580.7 | ||||||||
Net debt outstanding (3) | 985.1 | 981.1 | 878.1 | 950.5 | 1,255.9 | 1,152.8 | 1,061.9 | 1,096.0 | ||||||||
Weighted average shares outstanding | 345.6 | 342.8 | 340.4 | 333.2 | 318.6 | 317.2 | 315.9 | 314.7 | ||||||||
Weighted average shares outstanding, diluted | 345.6 | 342.8 | 340.7 | 333.5 | 319.1 | 317.8 | 316.6 | 315.2 | ||||||||
Shares outstanding, end of period | 347.1 | 344.2 | 341.5 | 339.3 | 319.4 | 317.8 | 316.5 | 315.3 | ||||||||
CAPITAL EXPENDITURES | ||||||||||||||||
Geological and geophysical | 2.5 | 8.0 | 3.1 | 2.3 | 4.7 | 3.5 | 3.5 | 5.9 | ||||||||
Drilling and completions | 108.5 | 117.9 | 51.8 | 83.0 | 164.4 | 154.9 | 181.6 | 159.1 | ||||||||
Plant and facilities | 37.3 | 37.8 | 43.2 | 43.7 | 78.2 | 58.8 | 49.4 | 75.0 | ||||||||
Administrative assets | 1.2 | 0.5 | 0.3 | 0.5 | 2.0 | 1.0 | 1.6 | 2.0 | ||||||||
Total capital expenditures | 149.5 | 164.2 | 98.4 | 129.5 | 249.3 | 218.2 | 236.1 | 242.0 | ||||||||
Undeveloped land purchased at Crown land sales | 4.6 | 0.6 | 0.1 | 1.4 | 18.0 | 21.9 | 16.6 | 5.8 | ||||||||
Total capital expenditures including undeveloped land purchases | 154.1 | 164.8 | 98.5 | 130.9 | 267.3 | 240.1 | 252.7 | 247.8 | ||||||||
Acquisitions | 0.3 | — | 14.1 | — | — | 37.3 | 5.5 | 30.7 | ||||||||
Dispositions | (42.2 | ) | (20.7 | ) | (14.9 | ) | (11.0 | ) | (2.4 | ) | (5.1 | ) | (31.8 | ) | — | |
Total capital expenditures, land purchases and net acquisitions and dispositions | 112.2 | 144.1 | 97.7 | 119.9 | 264.9 | 272.3 | 226.4 | 278.5 | ||||||||
OPERATING | ||||||||||||||||
Production | ||||||||||||||||
Crude oil (bbl/d) | 33,899 | 29,397 | 31,958 | 35,851 | 37,442 | 35,871 | 35,317 | 37,478 | ||||||||
Condensate (bbl/d) | 3,631 | 3,361 | 3,139 | 3,591 | 3,448 | 3,862 | 4,462 | 2,887 | ||||||||
Natural gas (MMcf/d) | 469.1 | 425.1 | 426.0 | 459.6 | 432.1 | 424.5 | 397.2 | 369.6 | ||||||||
NGLs (bbl/d) | 3,523 | 3,653 | 3,795 | 4,314 | 5,075 | 5,056 | 4,179 | 3,743 | ||||||||
Total (boe/d) | 119,243 | 107,261 | 109,900 | 120,354 | 117,986 | 115,530 | 110,165 | 105,699 | ||||||||
Average realized prices, prior to hedging | ||||||||||||||||
Crude oil ($/bbl) | 49.24 | 52.43 | 64.49 | 48.73 | 72.49 | 93.34 | 102.14 | 95.58 | ||||||||
Condensate ($/bbl) | 49.80 | 53.00 | 64.84 | 49.12 | 74.04 | 95.55 | 103.72 | 100.11 | ||||||||
Natural gas ($/Mcf) | 2.59 | 3.03 | 2.88 | 3.05 | 4.15 | 4.46 | 4.99 | 5.60 | ||||||||
NGLs ($/bbl) | 10.73 | 5.68 | 9.53 | 16.07 | 32.69 | 39.61 | 39.51 | 48.54 | ||||||||
Oil equivalent ($/boe) | 26.01 | 28.22 | 32.10 | 28.20 | 41.78 | 50.28 | 56.44 | 57.91 | ||||||||
TRADING STATISTICS | ||||||||||||||||
($, based on intra-day trading) | ||||||||||||||||
High | 22.49 | 21.98 | 25.60 | 25.87 | 29.85 | 32.60 | 33.68 | 30.66 | ||||||||
Low | 15.39 | 15.57 | 21.01 | 20.75 | 22.70 | 28.54 | 30.30 | 27.52 | ||||||||
Close | 16.70 | 17.64 | 21.40 | 21.76 | 25.16 | 29.55 | 32.49 | 30.45 | ||||||||
Average daily volume (thousands) | 2,224 | 1,736 | 1,424 | 1,944 | 1,886 | 1,205 | 1,037 | 1,248 |
(1) | Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. |
(2) | Dividends per share are based on the number of shares outstanding at each dividend record date. |
(3) | Refer to the sections entitled "Capitalization, Financial Resources and Liquidity" and “Additional GAAP Measures” contained within this MD&A. |
ARC Resources Ltd. | Page 48 |