U.S. SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of
Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934
|
|
|
For May 14, 2015 |
|
Commission File Number: 1-15226 |
ENCANA CORPORATION
(Translation of registrants name into English)
Suite 4400, 500 Centre Street SE
PO Box 2850
Calgary,
Alberta, Canada T2P 2S5
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form
20-F ¨ Form 40-F x
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T
Rule 101(b)(7): ¨
DOCUMENTS FILED AS PART OF THIS FORM 6-K
See the Exhibit Index to this Form 6-K.
SIGNATURES
Pursuant to the requirements
of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: May 14, 2015
|
|
|
|
|
ENCANA CORPORATION |
(Registrant) |
|
|
By: |
|
/s/ Jocelyn S. Salazar |
|
|
Name: |
|
Jocelyn S. Salazar |
|
|
Title: |
|
Assistant Corporate Secretary |
Form 6-K Exhibit Index
|
|
|
Exhibit No. |
|
|
|
|
99.1 |
|
Interim Report to Shareholders for the period ended March 31, 2015, including the Unaudited Interim Condensed Consolidated Financial Statements and Managements Discussion and Analysis for the said period. |
Exhibit 99.1
2015 Q1 Report
For the period ending
March 31, 2015
encana
Q1 Report | for the period ended March 31, 2015
Encana reports solid first quarter operating performance and continued liquids growth
Calgary, Alberta (May 12, 2015) TSX, NYSE: ECA
Encana delivered strong results in the first quarter, during which it grew liquids production and cash flow, advanced the development of its four most
strategic assets and prudently managed its balance sheet. Highlights include:
|
|
cash flow of approximately $495 million, up 31 percent from the fourth quarter of 2014 |
|
|
liquids production of approximately 120,700 barrels per day (bbls/d), up 78 percent year-over-year and 13 percent from the fourth quarter of 2014 |
|
|
significant improvements in well performance, drilling and completion cycle times and cost savings in the companys four most strategic assets, the Montney, Duvernay, Eagle Ford and Permian |
|
|
approximately 80 percent of capital invested in the companys four most strategic assets |
|
|
continued efficiencies that have the company on track to deliver the full-year capital savings of $300 million and direct operating cost savings of $75 million embedded in its 2015 guidance |
|
|
completed a bought deal common share offering in March, and in early April used the net proceeds, along with cash on hand, to redeem approximately $1.3 billion of long-term debt |
Through the continued advancement of our strategy, our first quarter results demonstrate the impact of our high quality portfolio, focused capital
investment and prudent balance sheet management, said Doug Suttles, Encana President & CEO. Through innovation, execution improvements and teamwork, we continue to drive greater performance and efficiency throughout the
company.
Consistent with its strategy to invest capital to grow higher margin production, and supported by its portfolio transformation in 2014,
Encanas liquids volumes have increased 78 percent year-over-year. Approximately 74 percent of liquids production in the first quarter was generated from the Montney, Duvernay, Eagle Ford and Permian. Encanas first quarter investment in
these assets is expected to deliver a significant increase of liquids production in the second half of 2015.
Weve made good progress repositioning our portfolio which now includes core positions in some of the
highest netback basins in North America, said Suttles. Our four most strategic assets are the growth engine of the company, currently generating better margins than the entire portfolio did in 2013 when both oil and natural gas prices
were substantially higher.
Total company production averaged approximately 430,100 barrels of oil equivalent per day (BOE/d) during the
quarter, down from about 536,100 BOE/d in the same quarter in 2014, reflecting the sale of lower margin assets and the companys shift to a higher margin, liquids-weighted production mix.
The company continues to prudently manage its balance sheet and in April used the net proceeds from its common share offering, and cash on hand, to redeem
approximately $1.3 billion of long-term debt. The redemption of this debt required a one-time early interest payment of approximately $165 million, which is expected to save Encana a gross amount of over $200 million in future
interest expense and further enhance its financial flexibility.
As announced in its revised guidance, and based on assumptions of $50 WTI and $3 NYMEX
prices, Encana expects to fully fund its 2015 capital program and dividend from anticipated cash flow along with proceeds from previously announced divestitures of certain Clearwater assets and Montney midstream infrastructure. Both transactions
closed during the first quarter generating net proceeds of about $827 million after closing adjustments.
Encana generated first quarter cash flow of
$495 million or $0.65 per share, compared to $1.1 billion or $1.48 per share in the first quarter of 2014, a decrease primarily attributable to sharp declines in oil and natural gas prices. Operating earnings were $9 million or $0.01 per share,
compared to $515 million or $0.70 per share in the first quarter of 2014. First quarter 2015 per share amounts include the weighted average proportion of the additional 98,458,975 common shares issued through the companys recent bought
deal common share offering.
On a reported basis, due primarily to a
non-cash, after-tax ceiling test impairment and a non-operating foreign exchange loss, Encana recorded a net loss of $1.7 billion for the first quarter.
|
|
|
|
|
First Quarter Report |
Q1 Report | for the period ended March 31, 2015
THIRD QUARTER OPERATIONAL HIGHLIGHTS
INNOVATION DELIVERS BETTER WELLS, LOWER COSTS AND CREATES LINE OF SIGHT TO LARGER DRILLING INVENTORY
Our team is doing a good job significantly improving well performance, lowering costs all across our operations and gaining line of sight to increased
drilling inventory, said Suttles. We are leveraging the power of our portfolio by taking proven drilling and completion techniques from areas such as the Haynesville, Piceance and Montney and applying them in the Permian, Eagle Ford and
Duvernay.
Encana continues to evolve its resource play hub (RPH) model, applying simultaneous drilling and completions operations on multi-well
pads to drive greater productivity and cost efficiencies. Through the optimization of well completions, and the application of high intensity hydraulic fracturing, the company is increasing initial production rates and delivering stronger well
performance.
PERMIAN: RPH MODEL ACCELERATING DEVELOPMENT
In its first full quarter of activity, Encana started full RPH development, drilled its first multi-well pad, began deploying simultaneous operations and
tested high intensity fracs of up to 3,000 pounds of sand per foot of lateral length. The company has realized cost savings of approximately $700,000 per well compared to average well costs from the fourth quarter of 2014. Encana continues to test
tighter
inter-well spacing, stacked laterals and cluster spacing in the play, with the company actively working in the Wolfcamp A, B and C and Lower Spraberry zones. The company ran six horizontal rigs
and seven vertical rigs, drilled 46 net wells and delivered average liquids production of 26,700 bbls/d. While production was impacted by adverse weather, the company exited the quarter at 37,900 BOE/d, an increase of 22 percent since December 2014.
Encana is on track to grow net annualized production to approximately 45,000 BOE/d.
EAGLE FORD: IMPROVING PRODUCTION AND LOWERING COSTS
Encana drilled its fastest three wells to date during the quarter and reduced normalized drilling costs by 15 percent compared to the fourth quarter of 2014.
In total, Encana has reduced its drilling and completion costs by $1 million per well since acquiring its position in the play last year. Encana sees potential for stacked pay in future development with current production performance driven by
larger frac designs, higher sand concentration and tighter cluster spacing which has been reduced to less than 50 feet. The company is seeing promising early results from new wells in an area known as the Graben. Base optimization efforts reduced
decline rates by 50 percent over the first quarter. Twenty-seven net wells were drilled in the play during the quarter and liquids production averaged 36,000 bbls/d. Encana remains on track to grow net annualized production to approximately
50,000 BOE/d.
|
|
|
|
|
|
|
First Quarter Report |
|
|
Q1 Report | for the period ended March 31, 2015
DUVERNAY: REDUCED DRILLING AND COMPLETION COSTS
Encanas RPH model continues to deliver efficiencies with completions costs down approximately 25 percent and drilling costs down approximately 45 percent
compared to the first quarter of 2014. Encana successfully piloted dual-frac spread operations on an eight-well pad for $7.6 million per well, a cost saving of approximately 10 percent. The company delivered pace-setting results during the first
quarter, drilling its lowest cost well to date at $3.2 million at a lateral length of 6,800 feet. In addition, Encana drilled the longest lateral in the play to date at 9,350 feet at a cost of $3.5 million. In 2014, Encana completed work on its
water delivery and disposal infrastructure and as a result is now saving approximately 70 percent on water handling costs in the play compared to last year. Six net wells were drilled in the first quarter and liquids production averaged 2,800
bbls/d. Expected net production for 2015 is approximately 10,000 BOE/d.
MONTNEY: COMPLETION DESIGN DRIVING OVER 30 PERCENT PRODUCTION IMPROVEMENT
Encana continues to enhance completion design in the Montney, resulting in over 30 percent production improvement on new wells. The company continues
to improve its drilling performance with the fastest well to date drilled in 13 days at a lateral length of 6,560 feet, a 10 percent improvement
from the 2014 average. Encana realized a $1 million reduction in drilling and completion costs during the first quarter compared to its 2014 average in the play. During the quarter, Encana
finished mechanical construction of the Saturn 15-27 compressor station, which is part of the recently announced Montney midstream transaction. The station will provide an additional 200 million cubic feet per day (MMcf/d) of processing
capacity and is expected to be online in June. Eight net wells were drilled in the first quarter and natural gas and liquids production was 717 MMcf/d and 23,500 bbls/d, respectively. Net production for 2015 is expected to be greater than 140,000
BOE/d.
ENCANAS RISK MANAGEMENT PROGRAM
At
March 31, 2015, Encana has hedged approximately 1,000 MMcf/d of expected April to December 2015 natural gas production using NYMEX fixed price contracts at an average price of $4.29 per thousand cubic feet (Mcf). In addition, Encana has hedged
approximately 55,800 bbls/d of expected April to December 2015 oil production using WTI fixed price contracts at an average price of $62.09 per bbl.
DIVIDEND DECLARED
On May 11, 2015, the Board of
Directors declared a dividend of $0.07 per share payable on June 30, 2015 to common shareholders of record as of June 15, 2015.
|
|
|
|
|
First Quarter Report |
Q1 Report | for the period ended March 31, 2015
FIRST QUARTER HIGHLIGHTS
FINANCIAL SUMMARY
|
|
|
|
|
|
|
|
|
(for the period ended March 31)
($ millions, except per share amounts) |
|
Q1 2015 |
|
|
Q1 2014 |
|
Cash flow1 |
|
|
495 |
|
|
|
1,094 |
|
Per share diluted |
|
|
0.65 |
|
|
|
1.48 |
|
Operating earnings1 |
|
|
9 |
|
|
|
515 |
|
Per share diluted |
|
|
0.01 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS RECONCILIATION SUMMARY |
|
|
|
|
|
|
|
|
Net earnings attributable to common shareholders |
|
|
(1,707 |
) |
|
|
116 |
|
After-tax (addition) deduction: |
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
|
(98 |
) |
|
|
(203 |
) |
Impairments |
|
|
(1,222 |
) |
|
|
|
|
Restructuring charges |
|
|
|
|
|
|
(10 |
) |
Non-operating foreign exchange gain (loss) |
|
|
(508 |
) |
|
|
(194 |
) |
Gain (loss) on divestitures |
|
|
10 |
|
|
|
|
|
Income tax adjustments |
|
|
102 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
Operating earnings1 |
|
|
9 |
|
|
|
515 |
|
Per share diluted |
|
|
0.01 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
|
|
(1) |
Cash flow and operating earnings are non-GAAP measures as defined in Note 1. |
PRODUCTION SUMMARY
|
|
|
|
|
|
|
|
|
|
|
|
|
(for the period ended March 31)
(after royalties) |
|
Q1 2015 |
|
|
Q1 2014 |
|
|
% D |
|
Natural gas (MMcf/d) |
|
|
1,857 |
|
|
|
2,809 |
|
|
|
(34 |
) |
Liquids (Mbbls/d) |
|
|
120.7 |
|
|
|
67.9 |
|
|
|
78 |
|
NATURAL GAS AND LIQUIDS PRICES
|
|
|
|
|
|
|
|
|
|
|
Q3 2014 |
|
|
Q3 2013 |
|
Natural Gas |
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu) |
|
|
4.06 |
|
|
|
3.58 |
|
Encana realized gas price1 ($/Mcf) |
|
|
4.03 |
|
|
|
4.00 |
|
|
|
|
|
|
|
|
|
|
Oil and NGLs ($/bbl) |
|
|
|
|
|
|
|
|
WTI |
|
|
48.64 |
|
|
|
98.68 |
|
Encana realized NGLs price |
|
|
37.83 |
|
|
|
69.19 |
|
|
|
|
|
|
|
|
|
|
(1) |
Realized prices include the impact of financial hedging. |
|
|
|
|
|
|
|
First Quarter Report |
|
|
|
Q1 Report | for the period ended March 31, 2015
|
ENCANA CORPORATION
Encana is a leading North American energy producer that is focused on developing its strong portfolio of resource plays, held directly and indirectly through
its subsidiaries, producing natural gas, oil and natural gas liquids (NGLs). By partnering with employees, community organizations and other businesses, Encana contributes to the strength and sustainability of the communities where it operates.
Encana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.
IMPORTANT INFORMATION
Encana reports in U.S. dollars unless otherwise noted. Production, sales and reserves estimates are reported on an after-royalties basis, unless otherwise
noted. Per share amounts for cash flow and earnings are on a diluted basis. The term liquids is used to represent oil, NGLs and condensate. The term liquids rich is used to represent natural gas streams with associated liquids volumes. Unless
otherwise specified or the context otherwise requires, reference to Encana or to the company includes reference to subsidiaries of and partnership interests held by Encana Corporation and its subsidiaries.
NOTE 1: NON-GAAP MEASURES
This news release contains
references to non-GAAP measures as follows:
|
|
Cash flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets. |
|
|
Operating earnings is a non-GAAP measure defined as net earnings attributable to common shareholders excluding non-recurring or non-cash items that management believes reduces the comparability of the companys
financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income
taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate. |
These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information
regarding Encanas liquidity and its ability to generate funds to finance its operations.
ADVISORY REGARDING OIL AND GAS INFORMATION
Encana uses the term resource play. Resource play is a term used by Encana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical
section, which when compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate.
30-day initial production and short-term rates are not necessarily indicative of long-term performance or of ultimate recovery.
In this news release, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one
barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at
the well head. Given that the value ratio based on the current price of natural gas as compared to oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS In the interests of providing Encana shareholders and potential investors with information
regarding Encana, including managements assessment of Encanas and its subsidiaries future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of
applicable securities legislation, collectively referred to herein as forward-looking statements. Forward-looking statements in this news release include, but are not limited to:
|
|
on track to deliver efficiencies and full-year capital savings of $300 million and operating cost savings of $75 million |
|
|
focused investment in assets expected to deliver a significant increase of liquids production in the second half of 2015 |
|
|
anticipated future interest expense savings while further enhancing its financial flexibility |
|
|
the companys expectation to fully fund its 2015 capital program and dividend with anticipated cash flow and proceeds from divestitures |
|
|
expected hedging activities |
|
|
expected net production for 2015 |
|
|
the continued evolution of the companys resource play hub model to drive greater productivity and cost efficiencies |
|
|
potential stacked pay and future performance driven by new technology |
|
|
anticipated increased initial production rates and well performance |
|
|
anticipated 2015 capital investment |
|
|
the expectation of meeting the targets in the companys 2015 corporate guidance
|
|
|
|
|
|
First Quarter Report |
Q1 Report | for the period ended March 31, 2015
Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance
that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the
possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the companys actual performance and financial results in future periods to differ materially from any estimates or
projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things:
|
|
commodity price volatility |
|
|
assumptions based upon the companys current guidance |
|
|
fluctuations in currency and interest rates |
|
|
risks inherent in the companys and its subsidiaries marketing operations, including credit risks |
|
|
imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource plays and other sources not currently classified as proved, probable or possible reserves or economic
contingent resources, including future net revenue estimates |
|
|
potential disruption or unexpected technical difficulties in developing new facilities |
|
|
risks associated with technology |
|
|
the companys ability to acquire or find additional reserves |
|
|
availability of hedges at attractive prices and hedging activities resulting in realized and unrealized losses business interruption and casualty losses |
|
|
risk of the company not operating all of its properties and assets |
|
|
risk of downgrade in credit rating and its adverse effects |
|
|
liability for indemnification obligations to third parties |
|
|
variability of dividends to be paid |
|
|
its ability to generate sufficient cash flow from operations to meet its current and future obligations |
|
|
its ability to access external sources of debt and equity capital |
|
|
the timing and the costs of well and pipeline construction |
|
|
risk that the company may not conclude divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements (such transactions may include third-party capital
investments,
|
|
|
farm-outs or partnerships, which Encana may refer to from time to time as partnerships or joint ventures and the funds received in respect thereof which Encana may refer
to from time to time as proceeds, deferred purchase price and/or carry capital, regardless of the legal form) as a result of various conditions not being met |
|
|
changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations |
|
|
political and economic conditions in the countries in which the company operates |
|
|
risks associated with existing and potential future lawsuits and regulatory actions made against the company |
|
|
risk arising from price basis differential |
|
|
the companys ability to secure adequate product transportation |
|
|
and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Encana |
Although Encana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations
will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. In addition, assumptions relating to such forward-looking statements generally include Encanas current expectations and projections
made in light of, and generally consistent with, its historical experience and its perception of historical trends.
Forward-looking information
respecting anticipated 2015 cash flow for Encana is based upon, among other things, achieving average production for 2015 of between 1.60 Bcf/d and 1.70 Bcf/d of natural gas and 130,000 bbls/d to 150,000 bbls/d of liquids, commodity prices for
natural gas and liquids based on NYMEX $3.00 per MMBtu and WTI of $50 per bbl, an estimated U.S./Canadian dollar exchange rate of $0.80 and a weighted average number of outstanding shares for Encana of approximately 821 million.
Furthermore, the forward-looking statements contained in this news release are made as of the date hereof and, except as required by law, Encana undertakes no
obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
|
|
|
|
|
|
|
First Quarter Report |
|
|
Q1 Report | for the period ended March 31, 2015
Managements Discussion and Analysis
This Managements Discussion and Analysis (MD&A) for Encana Corporation (Encana or the Company) should be read
with the unaudited interim Condensed Consolidated Financial Statements for the period ended March 31, 2015 (Interim Condensed Consolidated Financial Statements), as well as the audited Consolidated Financial Statements and MD&A
for the year ended December 31, 2014.
The Consolidated Financial Statements and comparative information have been prepared in accordance with
United States (U.S.) generally accepted accounting principles (U.S. GAAP) and in U.S. dollars, except where another currency has been indicated. References to C$ are to Canadian dollars. Encanas financial results are
consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. Production volumes are presented on an after royalties
basis consistent with U.S. oil and gas reporting standards and the disclosure of U.S. oil and gas companies. The term liquids is used to represent oil, natural gas liquids (NGLs or NGL) and condensate. The term
liquids rich is used to represent natural gas streams with associated liquids volumes. This document is dated May 11, 2015.
For
convenience, references in this document to Encana, the Company, we, us, our and its may, where applicable, refer only to or include any relevant direct and indirect subsidiary
corporations and partnerships (Subsidiaries) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries.
Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures.
Non-GAAP measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Companys liquidity and its ability to generate funds to finance its
operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings; Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted Capitalization. Further information
regarding these measures can be found in the Non-GAAP Measures section of this MD&A, including reconciliations of Cash from Operating Activities to Cash Flow and Free Cash Flow, and of Net Earnings (Loss) Attributable to Common Shareholders to
Operating Earnings.
The following volumetric measures may be abbreviated throughout this MD&A: thousand cubic feet (Mcf); million
cubic feet (MMcf) per day (MMcf/d); barrel (bbl); thousand barrels (Mbbls) per day (Mbbls/d); barrels of oil equivalent (BOE) per day (BOE/d); thousand barrels of
oil equivalent (MBOE) per day (MBOE/d); million British thermal units (MMBtu).
Readers should also read the
Advisory section located at the end of this document, which provides information on Forward-Looking Statements and Oil and Gas Information.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Encanas Strategic Objectives
Encana is a leading North American energy producer that is focused on developing its strong portfolio of resource plays producing natural gas, oil and NGLs.
Encana is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company is pursuing the key business objectives of balancing its commodity portfolio, focusing capital investments in
strategic high return scalable projects, maintaining portfolio flexibility to respond to changing market conditions, maximizing profitability through operating efficiencies, reducing costs and preserving balance sheet strength.
Encana continually strives to improve operating efficiencies, foster technological innovation and lower its cost structures, while reducing its environmental
footprint through play optimization. The Companys resource play hub model utilizes highly integrated production facilities to develop resources by drilling multiple wells from central pad sites. Capital and operating efficiencies are achieved
through repeatable operations, optimizing equipment and processes and by applying continuous improvement techniques.
Encana hedges a portion of its
expected natural gas and oil production volumes. The Companys hedging program reduces volatility and helps sustain Cash Flow and operating netbacks during periods of lower prices. Further information on the Companys commodity price
positions as at March 31, 2015 can be found in the Results Overview section of this MD&A and in Note 20 to the Interim Condensed Consolidated Financial Statements.
Additional information on expected results can be found in Encanas 2015 Corporate Guidance on the Companys website www.encana.com.
Encanas Business
Encanas reportable segments
are determined based on the Companys operations and geographic locations as follows:
|
|
|
Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within Canada. |
|
|
|
USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S. |
|
|
|
Market Optimization is primarily responsible for the sale of the Companys proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third
party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market
Optimization sells substantially all of the Companys upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation. Financial information is presented on an after
eliminations basis within this MD&A. |
Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial
instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Results Overview
Highlights
In the three months ended March 31, 2015, Encana reported:
|
|
|
Cash Flow of $495 million and Operating Earnings of $9 million. |
|
|
|
Net Loss of $1,707 million, including an after-tax non-cash ceiling test impairment of $1,222 million. |
|
|
|
Average realized natural gas prices, including financial hedges, of $4.78 per Mcf. Average realized oil prices, including financial hedges, of $46.17 per bbl. Average realized NGL prices of $21.92 per bbl.
|
|
|
|
Average natural gas production volumes of 1,857 MMcf/d and average oil and NGL production volumes of 120.7 Mbbls/d. |
|
|
|
Dividends paid of $0.07 per share. |
|
|
|
Cash and cash equivalents of $2,030 million at period end. |
Significant developments for the Company during
the three months ended March 31, 2015 included the following:
|
|
|
Completed a bought deal offering of 85,616,500 common shares of Encana and the over-allotment option of an additional 12,842,475 common shares of Encana at a price of C$14.60 per common share (the Share
Offering). The Share Offering was completed during March 2015 for aggregate gross proceeds of approximately C$1.44 billion. |
|
|
|
Provided notice on March 5, 2015 to note holders that the Company would redeem its $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due January 18,
2018. On April 6, 2015, the Company used net proceeds from the Share Offering and cash on hand to complete the note redemptions. |
|
|
|
Closed the sale of the Companys working interest in certain properties in central and southern Alberta to Ember Resources Inc. on January 15, 2015 for proceeds of approximately C$558 million, after closing
adjustments. |
|
|
|
Closed the sale of certain natural gas gathering and compression assets in northeastern British Columbia to Veresen Midstream Limited Partnership (VMLP) on March 31, 2015 for cash consideration net to
Encana of approximately C$455 million, after closing adjustments. In conjunction with the sale, VMLP will undertake the expansion of future midstream services and will also provide natural gas gathering and processing in Montney to Encana and the
Cutbank Ridge Partnership (CRP). |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2013 |
|
($ millions, except as indicated) |
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
|
|
|
|
|
|
|
|
Cash Flow (1) |
|
$ |
495 |
|
|
$ |
377 |
|
|
$ |
807 |
|
|
$ |
656 |
|
|
$ |
1,094 |
|
|
$ |
677 |
|
|
$ |
660 |
|
|
$ |
665 |
|
$ per share - diluted |
|
|
0.65 |
|
|
|
0.51 |
|
|
|
1.09 |
|
|
|
0.89 |
|
|
|
1.48 |
|
|
|
0.91 |
|
|
|
0.89 |
|
|
|
0.90 |
|
|
|
|
|
|
|
|
|
|
Operating Earnings (1) |
|
|
9 |
|
|
|
35 |
|
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
|
|
226 |
|
|
|
150 |
|
|
|
247 |
|
$ per share - diluted |
|
|
0.01 |
|
|
|
0.05 |
|
|
|
0.38 |
|
|
|
0.23 |
|
|
|
0.70 |
|
|
|
0.31 |
|
|
|
0.20 |
|
|
|
0.34 |
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(1,707 |
) |
|
|
198 |
|
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
|
|
(251 |
) |
|
|
188 |
|
|
|
730 |
|
$ per share - basic & diluted |
|
|
(2.25 |
) |
|
|
0.27 |
|
|
|
3.79 |
|
|
|
0.37 |
|
|
|
0.16 |
|
|
|
(0.34 |
) |
|
|
0.25 |
|
|
|
0.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
1,249 |
|
|
|
2,254 |
|
|
|
2,285 |
|
|
|
1,588 |
|
|
|
1,892 |
|
|
|
1,423 |
|
|
|
1,392 |
|
|
|
1,984 |
|
|
|
|
|
|
|
|
|
|
Realized Hedging Gain (Loss), before tax |
|
|
240 |
|
|
|
124 |
|
|
|
28 |
|
|
|
(102 |
) |
|
|
(141 |
) |
|
|
174 |
|
|
|
175 |
|
|
|
52 |
|
Unrealized Hedging Gain (Loss), before tax |
|
|
(136 |
) |
|
|
489 |
|
|
|
231 |
|
|
|
9 |
|
|
|
(285 |
) |
|
|
(301 |
) |
|
|
(128 |
) |
|
|
469 |
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow |
|
|
702 |
|
|
|
821 |
|
|
|
982 |
|
|
|
800 |
|
|
|
1,315 |
|
|
|
901 |
|
|
|
794 |
|
|
|
788 |
|
Upstream Operating Cash Flow Excluding Realized Hedging (1) |
|
|
454 |
|
|
|
694 |
|
|
|
952 |
|
|
|
898 |
|
|
|
1,455 |
|
|
|
728 |
|
|
|
622 |
|
|
|
737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
736 |
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
717 |
|
|
|
641 |
|
|
|
639 |
|
Net Acquisitions & (Divestitures) (2) |
|
|
(838 |
) |
|
|
50 |
|
|
|
(2,007 |
) |
|
|
652 |
|
|
|
(24 |
) |
|
|
(72 |
) |
|
|
(51 |
) |
|
|
(312 |
) |
|
|
|
|
|
|
|
|
|
Free Cash Flow (1) |
|
|
(241 |
) |
|
|
(480 |
) |
|
|
209 |
|
|
|
96 |
|
|
|
583 |
|
|
|
(40 |
) |
|
|
19 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Ceiling Test Impairments, after tax |
|
|
(1,222 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) on Divestitures, after tax |
|
|
10 |
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,857 |
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
2,744 |
|
|
|
2,723 |
|
|
|
2,766 |
|
Oil & NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
79.2 |
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
|
|
33.0 |
|
|
|
27.2 |
|
|
|
22.9 |
|
NGLs |
|
|
41.5 |
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
|
|
33.0 |
|
|
|
31.0 |
|
|
|
24.7 |
|
Total Oil & NGLs |
|
|
120.7 |
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
66.0 |
|
|
|
58.2 |
|
|
|
47.6 |
|
Total Production (MBOE/d) |
|
|
430.1 |
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
|
|
523.4 |
|
|
|
512.1 |
|
|
|
508.6 |
|
|
|
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
72 |
|
|
|
74 |
|
|
|
78 |
|
|
|
86 |
|
|
|
87 |
|
|
|
87 |
|
|
|
89 |
|
|
|
91 |
|
Oil & NGLs |
|
|
28 |
|
|
|
26 |
|
|
|
22 |
|
|
|
14 |
|
|
|
13 |
|
|
|
13 |
|
|
|
11 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
A non-GAAP measure, which is defined in the Non-GAAP Measures section of this MD&A. |
(2) |
Excludes the impact of the PrairieSky Royalty Ltd. divestiture and the Athlon Energy Inc. acquisition during 2014, as summarized in the Net Capital Investment section of this MD&A. |
Encanas quarterly net earnings can be significantly impacted by fluctuations in commodity prices, realized and unrealized hedging gains and losses,
production volumes, foreign exchange rates, ceiling test impairments and gains or losses on divestitures, which are provided in the Financial Results table and Prices and Foreign Exchange Rates table within this MD&A. Quarterly net earnings are
also impacted by Encanas interim income tax expense calculated using the estimated annual effective income tax rate as discussed in the Other Operating Results section of this MD&A. Quarterly net earnings are also impacted by acquisition
and divestiture transactions, which are discussed in the Net Capital Investment section of this MD&A.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Under full cost accounting, the carrying amount of Encanas natural gas and oil properties within each
country cost centre is subject to a ceiling test performed quarterly. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax
future net cash flows from proved reserves as calculated under Securities and Exchange Commission (SEC) requirements using the 12-month average trailing prices and discounted at 10 percent.
In the first quarter of 2015, the Company recognized an after-tax non-cash ceiling test impairment of $1,222 million in the U.S. cost centre. The non-cash
ceiling test impairment primarily resulted from the decline in the 12- month average trailing commodity prices. Further declines in the 12-month average trailing commodity prices could reduce proved reserves values and result in the recognition of
future ceiling test impairments. Future ceiling test impairments can also result from changes to reserves estimates, future development costs, capitalized costs and unproved property costs. Proceeds received from natural gas and oil divestitures are
generally deducted from the Companys capitalized costs and can reduce the likelihood of ceiling test impairments.
The Company believes that the
discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair market value of Encanas natural gas and oil properties or the future net cash flows expected to
be generated from such properties. The discounted after-tax future net cash flows do not consider the fair market value of unamortized unproved properties, or probable or possible natural gas and liquids reserves. In addition, there is no
consideration given to the effect of future changes in commodity prices. Encana manages its business using estimates of reserves and resources based on forecast prices and costs.
Three months ended March 31, 2015 versus March 31, 2014
Cash Flow of $495 million decreased $599 million in the three months ended March 31, 2015 primarily due to the following significant items:
|
|
|
Average realized natural gas prices, excluding financial hedges, were $3.53 per Mcf compared to $6.37 per Mcf in 2014 reflecting lower benchmark prices. Lower realized natural gas prices decreased revenues $472 million.
Average realized liquids prices, excluding financial hedges, were $34.13 per bbl compared to $69.23 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices decreased revenues $208 million. |
|
|
|
Average natural gas production volumes of 1,857 MMcf/d decreased 952 MMcf/d from 2,809 MMcf/d in 2014 primarily due to divestitures during 2014, natural declines in the USA Operations and lower production from Deep
Panuke, partially offset by a successful drilling program in Montney. Lower natural gas volumes decreased revenues $550 million. Average oil and NGL production volumes of 120.7 Mbbls/d increased 52.8 Mbbls/d from 67.9 Mbbls/d in 2014 primarily due
to acquisitions during 2014 and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures during 2014. Higher oil and NGL volumes increased revenues $156 million. |
|
|
|
Realized financial hedging gains before tax were $240 million compared to losses of $141 million in 2014. |
|
|
|
Production and mineral taxes decreased $28 million primarily due to divestitures during 2014 and lower commodity prices, partially offset by acquisitions during 2014. |
|
|
|
Transportation and processing expense decreased $39 million primarily due to divestitures during 2014 and the lower U.S./Canadian dollar exchange rate, partially offset by higher liquids volumes processed in Montney.
|
Operating Earnings of $9 million decreased $506 million primarily due to the items discussed in the Cash Flow section. Operating Earnings
for the first quarter of 2015 were also impacted by a higher foreign exchange loss on the revaluation of other monetary assets and liabilities, higher depreciation, depletion and amortization (DD&A), lower long-term compensation
costs due to the decrease in the Encana share price and deferred tax.
Net Loss in the first quarter of 2015 was $1,707 million compared to Net Earnings
of $116 million in 2014 primarily due to an after-tax non-cash ceiling test impairment and the items discussed in the Cash Flow and Operating Earnings sections. Net Loss for the first quarter of 2015 was also impacted by a higher after-tax
non-operating foreign exchange loss and lower after-tax unrealized hedging losses.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Prices and Foreign Exchange Rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2013 |
|
(average for the period) |
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
|
|
|
|
|
|
|
|
Encana Realized Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Including Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
$ |
4.78 |
|
|
$ |
4.16 |
|
|
$ |
4.03 |
|
|
$ |
4.08 |
|
|
$ |
5.82 |
|
|
$ |
4.34 |
|
|
$ |
4.00 |
|
|
$ |
4.17 |
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
46.17 |
|
|
|
80.38 |
|
|
|
90.22 |
|
|
|
89.55 |
|
|
|
86.34 |
|
|
|
85.39 |
|
|
|
90.42 |
|
|
|
88.27 |
|
NGLs |
|
|
21.92 |
|
|
|
40.87 |
|
|
|
48.76 |
|
|
|
49.39 |
|
|
|
53.79 |
|
|
|
48.59 |
|
|
|
46.35 |
|
|
|
49.63 |
|
Total Oil & NGLs |
|
|
37.83 |
|
|
|
66.40 |
|
|
|
73.50 |
|
|
|
69.53 |
|
|
|
69.19 |
|
|
|
67.01 |
|
|
|
66.95 |
|
|
|
68.25 |
|
Total ($/BOE) |
|
|
31.24 |
|
|
|
35.55 |
|
|
|
35.06 |
|
|
|
30.75 |
|
|
|
39.22 |
|
|
|
31.23 |
|
|
|
28.85 |
|
|
|
29.08 |
|
|
|
|
|
|
|
|
|
|
Excluding Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
3.53 |
|
|
|
3.94 |
|
|
|
3.88 |
|
|
|
4.46 |
|
|
|
6.37 |
|
|
|
3.69 |
|
|
|
3.26 |
|
|
|
3.99 |
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
40.53 |
|
|
|
66.38 |
|
|
|
90.18 |
|
|
|
92.93 |
|
|
|
86.43 |
|
|
|
82.54 |
|
|
|
96.09 |
|
|
|
85.89 |
|
NGLs |
|
|
21.92 |
|
|
|
40.87 |
|
|
|
48.76 |
|
|
|
49.39 |
|
|
|
53.79 |
|
|
|
48.59 |
|
|
|
46.35 |
|
|
|
49.63 |
|
Total Oil & NGLs |
|
|
34.13 |
|
|
|
57.35 |
|
|
|
73.48 |
|
|
|
71.23 |
|
|
|
69.23 |
|
|
|
65.58 |
|
|
|
69.60 |
|
|
|
67.10 |
|
Total ($/BOE) |
|
|
24.82 |
|
|
|
32.25 |
|
|
|
34.36 |
|
|
|
32.93 |
|
|
|
42.12 |
|
|
|
27.63 |
|
|
|
25.23 |
|
|
|
27.99 |
|
|
|
|
|
|
|
|
|
|
Natural Gas Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu) |
|
|
2.98 |
|
|
|
4.00 |
|
|
|
4.06 |
|
|
|
4.67 |
|
|
|
4.94 |
|
|
|
3.60 |
|
|
|
3.58 |
|
|
|
4.09 |
|
AECO (C$/Mcf) |
|
|
2.95 |
|
|
|
4.01 |
|
|
|
4.22 |
|
|
|
4.68 |
|
|
|
4.76 |
|
|
|
3.15 |
|
|
|
2.82 |
|
|
|
3.59 |
|
Algonquin City Gate ($/MMBtu) |
|
|
11.41 |
|
|
|
4.99 |
|
|
|
2.97 |
|
|
|
4.23 |
|
|
|
20.28 |
|
|
|
7.80 |
|
|
|
3.98 |
|
|
|
4.63 |
|
Basis Differential ($/MMBtu) AECO/NYMEX |
|
|
0.57 |
|
|
|
0.44 |
|
|
|
0.16 |
|
|
|
0.40 |
|
|
|
0.60 |
|
|
|
0.59 |
|
|
|
0.89 |
|
|
|
0.56 |
|
|
|
|
|
|
|
|
|
|
Oil Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) ($/bbl) |
|
|
48.64 |
|
|
|
73.15 |
|
|
|
97.17 |
|
|
|
102.99 |
|
|
|
98.68 |
|
|
|
97.46 |
|
|
|
105.81 |
|
|
|
94.17 |
|
Edmonton Light Sweet (C$/bbl) |
|
|
51.94 |
|
|
|
75.69 |
|
|
|
97.16 |
|
|
|
105.61 |
|
|
|
99.83 |
|
|
|
86.58 |
|
|
|
103.65 |
|
|
|
92.67 |
|
|
|
|
|
|
|
|
|
|
Foreign Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average U.S./Canadian Dollar Exchange Rate |
|
|
0.806 |
|
|
|
0.881 |
|
|
|
0.918 |
|
|
|
0.917 |
|
|
|
0.906 |
|
|
|
0.953 |
|
|
|
0.963 |
|
|
|
0.977 |
|
Encanas financial results are influenced by fluctuations in commodity prices, price differentials and the U.S./Canadian
dollar exchange rate. In the first quarter of 2015, Encanas average realized natural gas price, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $1.25 per Mcf to Encanas average
realized natural gas price in the first quarter of 2015. The average realized natural gas price for production from Deep Panuke was $10.68 per Mcf in the first quarter of 2015 compared to $19.14 per Mcf in 2014 and increased Encanas average
realized natural gas price $0.77 per Mcf in the first quarter of 2015 compared to $1.27 per Mcf in 2014.
In the first quarter of 2015, Encanas
average realized oil and NGL prices, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $5.64 per bbl to Encanas average realized oil price in the first quarter of 2015.
As a means of managing commodity price volatility and its impact on cash flows, Encana enters into various financial hedge agreements. Unsettled derivative
financial contracts are recorded at the date of the financial statements based on the fair value of the contracts. Changes in fair value result from volatility in forward curves of commodity prices and changes in the balance of unsettled contracts
between periods. The changes in fair value are recognized in revenue as unrealized hedging gains and losses. Realized hedging gains and losses are recognized in revenue when derivative financial contracts are settled.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
At March 31, 2015, Encana has hedged approximately 1,000 MMcf/d of expected April to December 2015
natural gas production using NYMEX fixed price contracts at an average price of $4.29 per Mcf. In addition, Encana has hedged approximately 55.8 Mbbls/d of expected April to December 2015 oil production using WTI fixed price contracts at an average
price of $62.09 per bbl and approximately 1.2 Mbbls/d of expected 2016 oil production at an average price of $92.35 per bbl.
The Companys hedging
program helps sustain Cash Flow and operating netbacks during periods of lower prices. For additional information, see the Risk Management Financial Risks section of this MD&A.
Foreign Exchange
As disclosed in the Prices and Foreign
Exchange Rates table, the average U.S./Canadian dollar exchange rate decreased 0.100 in the first quarter of 2015 compared to 2014. The table below summarizes selected foreign exchange impacts on Encanas financial results in the first quarter
of 2015 compared to the same period in 2014.
|
|
|
|
|
|
|
|
|
|
|
$ millions |
|
|
$/BOE |
|
|
|
|
Increase (Decrease) in: |
|
|
|
|
|
|
|
|
Capital Investment |
|
$ |
(32 |
) |
|
|
|
|
Transportation and Processing Expense |
|
|
(24 |
) |
|
$ |
(0.61 |
) |
Operating Expense |
|
|
(10 |
) |
|
|
(0.26 |
) |
Administrative Expense |
|
|
(8 |
) |
|
|
(0.20 |
) |
Depreciation, Depletion and Amortization |
|
|
(19 |
) |
|
|
(0.49 |
) |
Price Sensitivities
Natural gas and liquids prices fluctuate in response to changing market forces, creating varying impacts on Encanas financial results. The Companys
potential exposure to commodity price fluctuations is summarized in the table below, which shows the estimated effects that certain price changes would have had on the Companys Cash Flow and Operating Earnings for the first quarter of 2015.
The price sensitivities below are based on business conditions, transactions and production volumes during the first quarter of 2015. Accordingly, these sensitivities may not be indicative of financial results for other periods, under other economic
circumstances or with additional fluctuations in commodity prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact On |
|
($ millions, except as indicated) |
|
Price Change (1) |
|
|
Cash Flow |
|
|
Operating Earnings |
|
|
|
|
|
Increase or Decrease in: |
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Natural Gas Price |
|
+/- $ |
0.50/Mcf |
|
|
$ |
45 |
|
|
$ |
33 |
|
WTI Oil Price |
|
+/- $ |
10.00/bbl |
|
|
|
55 |
|
|
|
36 |
|
(1) |
Assumes only one variable changes while all other variables are held constant. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
(average daily, after royalties) |
|
2015 |
|
|
2014 |
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,857 |
|
|
|
2,809 |
|
|
|
|
Oil (Mbbls/d) |
|
|
79.2 |
|
|
|
32.1 |
|
NGLs (Mbbls/d) |
|
|
41.5 |
|
|
|
35.8 |
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs (Mbbls/d) |
|
|
120.7 |
|
|
|
67.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (MBOE/d) |
|
|
430.1 |
|
|
|
536.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
Natural Gas |
|
|
72 |
|
|
|
87 |
|
Oil & NGLs |
|
|
28 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
Production Volumes by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
(average daily, after royalties) |
|
Natural Gas (MMcf/d) |
|
|
Oil & NGLs (Mbbls/d) |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
717 |
|
|
|
620 |
|
|
|
23.3 |
|
|
|
16.2 |
|
Duvernay |
|
|
16 |
|
|
|
8 |
|
|
|
2.8 |
|
|
|
1.4 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
111 |
|
|
|
324 |
|
|
|
1.7 |
|
|
|
11.3 |
|
Bighorn |
|
|
4 |
|
|
|
246 |
|
|
|
|
|
|
|
12.1 |
|
Deep Panuke |
|
|
182 |
|
|
|
253 |
|
|
|
|
|
|
|
|
|
Other and emerging (1) |
|
|
98 |
|
|
|
117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canadian Operations |
|
|
1,128 |
|
|
|
1,568 |
|
|
|
27.8 |
|
|
|
41.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
36 |
|
|
|
|
|
|
|
36.0 |
|
|
|
|
|
Permian |
|
|
34 |
|
|
|
|
|
|
|
26.7 |
|
|
|
|
|
DJ Basin |
|
|
49 |
|
|
|
40 |
|
|
|
14.3 |
|
|
|
10.5 |
|
San Juan |
|
|
13 |
|
|
|
7 |
|
|
|
6.7 |
|
|
|
2.7 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
343 |
|
|
|
436 |
|
|
|
3.7 |
|
|
|
5.4 |
|
Haynesville |
|
|
230 |
|
|
|
331 |
|
|
|
|
|
|
|
|
|
Jonah |
|
|
|
|
|
|
282 |
|
|
|
|
|
|
|
4.7 |
|
East Texas |
|
|
|
|
|
|
113 |
|
|
|
|
|
|
|
1.2 |
|
Other and emerging |
|
|
24 |
|
|
|
32 |
|
|
|
5.5 |
|
|
|
2.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total USA Operations |
|
|
729 |
|
|
|
1,241 |
|
|
|
92.9 |
|
|
|
26.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production Volumes |
|
|
1,857 |
|
|
|
2,809 |
|
|
|
120.7 |
|
|
|
67.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production Volumes Growth Assets (1) |
|
|
865 |
|
|
|
675 |
|
|
|
114.1 |
|
|
|
31.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Montney has been realigned to include certain production volumes which were previously reported in Other and emerging. |
(2) |
Wheatland was previously presented as Clearwater. |
Growth assets includes Encanas top four strategic
assets Montney, Duvernay, Eagle Ford and Permian as well as the DJ Basin, San Juan and the Tuscaloosa Marine Shale (TMS), which represent additional high-quality investment opportunities. Other Upstream Operations includes
production volumes from plays that are not part of the Companys current strategic focus as well as prospective plays that are under appraisal, including the TMS, which is reported within Other and emerging in the USA Operations.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
The production volumes associated with the lands transferred to PrairieSky Royalty Ltd.
(PrairieSky) were included in Encanas Wheatland play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.
Three months ended March 31, 2015 versus March 31, 2014
In the first quarter of 2015, average natural gas production volumes of 1,857 MMcf/d decreased 952 MMcf/d from 2014. The USA Operations volumes were lower in
the first quarter of 2015 primarily due to the sales of the Jonah and East Texas properties in the second quarter of 2014 and natural declines in Haynesville and Piceance. The Canadian Operations volumes were lower in the first quarter of 2015
primarily due to the sale of the Bighorn assets in the third quarter of 2014, the sale of certain assets included in Wheatland in January 2015 and a production decline at Deep Panuke primarily due to a higher water production rate, partially offset
by a successful drilling program in Montney.
In the first quarter of 2015, average oil and NGL production volumes of 120.7 Mbbls/d increased 52.8 Mbbls/d
from 2014. The USA Operations volumes were higher in the first quarter of 2015 primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, and successful drilling programs in San
Juan, the DJ Basin and the TMS, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014. The Canadian Operations volumes were lower in the first quarter of 2015 primarily due to the sales of the Bighorn
assets and the Companys investment in PrairieSky in the third quarter of 2014, partially offset by a successful drilling program in Montney.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Net Capital Investment
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Canadian Operations |
|
$ |
151 |
|
|
$ |
281 |
|
USA Operations |
|
|
583 |
|
|
|
226 |
|
Market Optimization |
|
|
|
|
|
|
1 |
|
Corporate & Other |
|
|
2 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
736 |
|
|
|
511 |
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
35 |
|
|
|
23 |
|
Divestitures |
|
|
(873 |
) |
|
|
(47 |
) |
|
|
|
|
|
|
|
|
|
Net Acquisitions & (Divestitures) |
|
|
(838 |
) |
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
Net Capital Investment |
|
$ |
(102 |
) |
|
$ |
487 |
|
|
|
|
|
|
|
|
|
|
Capital Investment by Play
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
Montney (1) |
|
$ |
79 |
|
|
$ |
208 |
|
Duvernay |
|
|
70 |
|
|
|
71 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
|
|
|
|
18 |
|
Bighorn |
|
|
|
|
|
|
9 |
|
Deep Panuke |
|
|
2 |
|
|
|
(3 |
) |
Other and emerging (1) |
|
|
|
|
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
Total Canadian Operations |
|
$ |
151 |
|
|
$ |
281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
Eagle Ford |
|
$ |
197 |
|
|
$ |
|
|
Permian |
|
|
217 |
|
|
|
|
|
DJ Basin |
|
|
88 |
|
|
|
59 |
|
San Juan |
|
|
36 |
|
|
|
52 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
Piceance |
|
|
3 |
|
|
|
21 |
|
Haynesville |
|
|
2 |
|
|
|
38 |
|
Jonah |
|
|
|
|
|
|
11 |
|
East Texas |
|
|
|
|
|
|
10 |
|
Other and emerging |
|
|
40 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
Total USA Operations |
|
$ |
583 |
|
|
$ |
226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment Growth Assets (1) |
|
$ |
713 |
|
|
$ |
410 |
|
|
|
|
|
|
|
|
|
|
(1) |
Montney has been realigned to include certain capital investments which were previously reported in Other and emerging. |
(2) |
Wheatland was previously presented as Clearwater. |
Growth assets includes Encanas top four strategic
assets Montney, Duvernay, Eagle Ford and Permian as well as the DJ Basin, San Juan and the TMS, which represent additional high-quality investment opportunities. Other Upstream Operations includes capital investment from plays that are
not part of the Companys current strategic focus as well as prospective plays that are under appraisal, including the TMS, which is reported within Other and emerging in the USA Operations. For the first quarter of 2015, capital investment in
the TMS was $26 million (2014 $20 million).
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Capital investment associated with the lands transferred to PrairieSky was included in Encanas
Wheatland play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.
Three months ended March 31, 2015 versus
March 31, 2014
Capital investment during the first quarter of 2015 was $736 million compared to $511 million in 2014. The Companys disciplined
capital spending focused on investment in its growth assets, as well as executing drilling programs with joint venture partners. During the first quarter of 2015, capital spending in the Companys growth assets totaled $713 million (2014
$410 million), representing approximately 97 percent (2014 80 percent) of the Companys capital investment, with $563 million (2014 $279 million) spent on Encanas top four strategic assets.
Divestitures
Divestitures in the first quarter of 2015 were
$829 million in the Canadian Operations. This included approximately C$558 million ($468 million), after closing adjustments, for the sale of the Companys working interest in certain assets included in Wheatland located in central and southern
Alberta which comprised approximately 1.2 million net acres of land that contained over 6,800 producing wells. Encana retains a working interest in approximately 1.1 million net acres in the area. The Canadian Operations also included
approximately C$455 million ($359 million), after closing adjustments, in cash consideration net to Encana for the sale of certain natural gas gathering and compression assets in northeastern British Columbia to VMLP. In conjunction with the sale,
VMLP will undertake the expansion of future midstream services and will also provide natural gas gathering and processing in Montney to Encana and the CRP. Further information can be found in Note 15 to the Interim Condensed Consolidated Financial
Statements.
Amounts received from the divestiture transactions above have been deducted from the Canadian full cost pool.
2014 Capital Transactions
The following significant acquisition
and divestiture transactions, which occurred during 2014, have impacted the Companys production volume and operating cash flow variances for the first quarter of 2015:
|
|
|
|
|
|
|
|
|
Transaction |
|
Location |
|
|
Closing Date |
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
Divestiture of Encanas investment in PrairieSky (1) |
|
|
Alberta |
|
|
|
September 26, 2014 |
|
Sale of Bighorn assets |
|
|
Alberta |
|
|
|
September 30, 2014 |
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
Sale of Jonah properties |
|
|
Wyoming |
|
|
|
May 12, 2014 |
|
Sale of East Texas properties |
|
|
Texas |
|
|
|
June 19, 2014 |
|
Acquisition of properties in the Eagle Ford shale formation |
|
|
Texas |
|
|
|
June 20, 2014 |
|
Acquisition of Athlon Energy Inc. with assets in the Permian Basin (1) |
|
|
Texas |
|
|
|
November 13, 2014 |
|
(1) |
Transactions involved the disposition or acquisition of common shares and, therefore, were not part of the Companys net acquisition and divestiture activity for 2014. |
Refer to the annual MD&A for the year ended December 31, 2014 for a comprehensive discussion of these transactions.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Results of Operations
Canadian Operations
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
396 |
|
|
$ |
1,017 |
|
|
$ |
77 |
|
|
$ |
245 |
|
|
$ |
476 |
|
|
$ |
1,268 |
|
Realized Financial Hedging Gain (Loss) |
|
|
154 |
|
|
|
(75 |
) |
|
|
2 |
|
|
|
|
|
|
|
156 |
|
|
|
(75 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
550 |
|
|
|
942 |
|
|
|
79 |
|
|
|
245 |
|
|
|
632 |
|
|
|
1,193 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
5 |
|
Transportation and processing |
|
|
163 |
|
|
|
201 |
|
|
|
14 |
|
|
|
14 |
|
|
|
177 |
|
|
|
215 |
|
Operating |
|
|
36 |
|
|
|
84 |
|
|
|
6 |
|
|
|
6 |
|
|
|
42 |
|
|
|
92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
$ |
351 |
|
|
$ |
655 |
|
|
$ |
59 |
|
|
$ |
222 |
|
|
$ |
413 |
|
|
$ |
881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
Total |
|
|
|
(MMcf/d) |
|
|
(Mbbls/d) |
|
|
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
1,128 |
|
|
|
1,568 |
|
|
|
27.8 |
|
|
|
41.0 |
|
|
|
215.8 |
|
|
|
302.4 |
|
|
|
|
|
|
|
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
Total |
|
|
|
($/Mcf) |
|
|
($/bbl) |
|
|
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
3.89 |
|
|
$ |
7.17 |
|
|
$ |
30.65 |
|
|
$ |
66.36 |
|
|
$ |
24.30 |
|
|
$ |
46.20 |
|
Realized Financial Hedging Gain (Loss) |
|
|
1.52 |
|
|
|
(0.53 |
) |
|
|
0.78 |
|
|
|
(0.09 |
) |
|
|
8.04 |
|
|
|
(2.77 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
5.41 |
|
|
|
6.64 |
|
|
|
31.43 |
|
|
|
66.27 |
|
|
|
32.34 |
|
|
|
43.43 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
0.01 |
|
|
|
0.04 |
|
|
|
0.80 |
|
|
|
0.02 |
|
|
|
0.18 |
|
Transportation and processing |
|
|
1.60 |
|
|
|
1.42 |
|
|
|
5.82 |
|
|
|
3.80 |
|
|
|
9.12 |
|
|
|
7.87 |
|
Operating |
|
|
0.35 |
|
|
|
0.59 |
|
|
|
2.31 |
|
|
|
1.75 |
|
|
|
2.14 |
|
|
|
3.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Netback |
|
$ |
3.46 |
|
|
$ |
4.62 |
|
|
$ |
23.26 |
|
|
$ |
59.92 |
|
|
$ |
21.06 |
|
|
$ |
32.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Also includes other revenues and expenses, such as third party processing, with no associated volumes. |
(2) |
A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A. |
Three months ended
March 31, 2015 versus March 31, 2014
Operating Cash Flow of $413 million decreased $468 million primarily due to the following significant
items:
|
|
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $333 million. The average realized natural gas price for production from Deep Panuke was $10.68 per Mcf compared to $19.14 per Mcf in
2014 and increased the average realized natural gas price $1.30 per Mcf compared to $2.29 per Mcf in 2014. |
|
|
|
Lower liquids prices reflected lower benchmark prices, which decreased revenues $89 million. |
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
|
|
|
Average natural gas production volumes of 1,128 MMcf/d were lower by 440 MMcf/d, which decreased revenues $288 million. Average oil and NGL production volumes of 27.8 Mbbls/d were lower by 13.2 Mbbls/d, which decreased
revenues $79 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
|
|
Realized financial hedging gains were $156 million compared to losses of $75 million in 2014. |
|
|
|
Transportation and processing expense decreased $38 million primarily due to the sale of the Bighorn assets in the third quarter of 2014, the lower U.S./Canadian dollar exchange rate and the sale of certain assets
included in Wheatland in January 2015, partially offset by higher liquids volumes processed in Montney. |
|
|
|
Operating expense decreased $50 million primarily due to the sale of certain assets included in Wheatland in January 2015, lower long-term compensation costs due to the decrease in the Encana share price, the lower
U.S./Canadian dollar exchange rate, and the sale of the Bighorn assets in the third quarter of 2014. |
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
Depreciation, depletion & amortization |
|
$ |
105 |
|
|
$ |
172 |
|
Depletion rate ($/BOE) |
|
|
5.39 |
|
|
|
6.28 |
|
DD&A decreased primarily due to lower production volumes and the lower U.S./Canadian dollar exchange rate. The lower
depletion rate in the first quarter of 2015 resulted primarily from the lower U.S./Canadian dollar exchange rate, and the sales of the Bighorn assets and the Companys investment in PrairieSky in the third quarter of 2014.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
USA Operations
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
195 |
|
|
$ |
596 |
|
|
$ |
295 |
|
|
$ |
179 |
|
|
$ |
496 |
|
|
$ |
778 |
|
Realized Financial Hedging Gain (Loss) |
|
|
54 |
|
|
|
(65 |
) |
|
|
38 |
|
|
|
|
|
|
|
92 |
|
|
|
(65 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
249 |
|
|
|
531 |
|
|
|
333 |
|
|
|
179 |
|
|
|
588 |
|
|
|
713 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
4 |
|
|
|
29 |
|
|
|
15 |
|
|
|
13 |
|
|
|
19 |
|
|
|
42 |
|
Transportation and processing |
|
|
151 |
|
|
|
163 |
|
|
|
4 |
|
|
|
|
|
|
|
155 |
|
|
|
163 |
|
Operating |
|
|
49 |
|
|
|
68 |
|
|
|
75 |
|
|
|
8 |
|
|
|
125 |
|
|
|
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
$ |
45 |
|
|
$ |
271 |
|
|
$ |
239 |
|
|
$ |
158 |
|
|
$ |
289 |
|
|
$ |
434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
Total |
|
|
|
(MMcf/d) |
|
|
(Mbbls/d) |
|
|
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
729 |
|
|
|
1,241 |
|
|
|
92.9 |
|
|
|
26.9 |
|
|
|
214.3 |
|
|
|
233.7 |
|
|
|
|
|
|
|
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
Total |
|
|
|
($/Mcf) |
|
|
($/bbl) |
|
|
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
2.97 |
|
|
$ |
5.34 |
|
|
$ |
35.18 |
|
|
$ |
73.61 |
|
|
$ |
25.34 |
|
|
$ |
36.82 |
|
Realized Financial Hedging Gain (Loss) |
|
|
0.82 |
|
|
|
(0.58 |
) |
|
|
4.58 |
|
|
|
0.04 |
|
|
|
4.78 |
|
|
|
(3.07 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
3.79 |
|
|
|
4.76 |
|
|
|
39.76 |
|
|
|
73.65 |
|
|
|
30.12 |
|
|
|
33.75 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
0.06 |
|
|
|
0.26 |
|
|
|
1.80 |
|
|
|
5.46 |
|
|
|
0.97 |
|
|
|
1.99 |
|
Transportation and processing |
|
|
2.30 |
|
|
|
1.46 |
|
|
|
0.43 |
|
|
|
|
|
|
|
8.02 |
|
|
|
7.75 |
|
Operating |
|
|
0.75 |
|
|
|
0.61 |
|
|
|
8.96 |
|
|
|
3.16 |
|
|
|
6.44 |
|
|
|
3.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Netback |
|
$ |
0.68 |
|
|
$ |
2.43 |
|
|
$ |
28.57 |
|
|
$ |
65.03 |
|
|
$ |
14.69 |
|
|
$ |
20.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Also includes other revenues and expenses, such as third party processing, with no associated volumes. |
(2) |
A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A. |
Three months ended
March 31, 2015 versus 2014
Operating Cash Flow of $289 million decreased $145 million primarily due to the following significant items:
|
|
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $139 million. Lower liquids prices reflected lower benchmark prices, which decreased revenues $119 million. |
|
|
|
Average natural gas production volumes of 729 MMcf/d were lower by 512 MMcf/d, which decreased revenues $262 million. Average oil and NGL production volumes of 92.9 Mbbls/d were higher by 66.0 Mbbls/d, which increased
revenues $235 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
|
|
Realized financial hedging gains were $92 million compared to losses of $65 million in 2014. |
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
|
|
|
Production and mineral taxes decreased $23 million primarily due to the sale of the Jonah properties in the second quarter of 2014 and lower commodity prices, partially offset by the acquisitions of Eagle Ford and the
Permian assets in the second and fourth quarters of 2014, respectively. |
|
|
|
Operating expense increased $51 million primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, partially offset by the sales of the Jonah and East
Texas properties in the second quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price. |
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
Depreciation, depletion & amortization |
|
$ |
336 |
|
|
$ |
212 |
|
Depletion rate ($/BOE) |
|
|
16.96 |
|
|
|
10.09 |
|
Impairments |
|
|
1,916 |
|
|
|
|
|
DD&A increased primarily due to a higher depletion rate of $16.96 per BOE in 2015 compared to $10.09 per BOE in 2014,
partially offset by lower production volumes. The higher depletion rate in the first quarter of 2015 resulted primarily from the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, and a
decrease in proved reserves as a result of the sale of the Jonah properties in the second quarter of 2014.
In the first quarter of 2015, the USA
Operations recognized a before-tax non-cash ceiling test impairment of $1,916 million. The impairment primarily resulted from the decline in the 12-month average trailing commodity prices, which reduced the USA Operations proved reserves volumes and
values as calculated under SEC requirements.
The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark
prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
|
Henry Hub ($/MMBtu) |
|
|
WTI ($/bbl) |
|
12-Month Average Trailing Reserves Pricing (1) |
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015 |
|
|
3.88 |
|
|
|
82.72 |
|
December 31, 2014 |
|
|
4.34 |
|
|
|
94.99 |
|
March 31, 2014 |
|
|
3.99 |
|
|
|
98.46 |
|
(1) |
All prices were held constant in all future years when estimating reserves. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Market Optimization
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Revenues |
|
$ |
139 |
|
|
$ |
244 |
|
Expenses |
|
|
|
|
|
|
|
|
Operating |
|
|
16 |
|
|
|
13 |
|
Purchased product |
|
|
121 |
|
|
|
228 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Market Optimization revenues and purchased product expense relate to activities that provide operational flexibility for
transportation commitments, product type, delivery points and customer diversification. Revenues and purchased product expense decreased in the first quarter of 2015 compared to 2014 primarily due to lower commodity prices, partially offset by
higher volumes required for optimization.
Corporate and Other
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Revenues |
|
$ |
(110 |
) |
|
$ |
(258 |
) |
Expenses |
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
8 |
|
|
|
1 |
|
Operating |
|
|
6 |
|
|
|
10 |
|
Depreciation, depletion and amortization |
|
|
25 |
|
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(149 |
) |
|
$ |
(300 |
) |
|
|
|
|
|
|
|
|
|
Revenues mainly include unrealized hedging gains or losses recorded on derivative financial contracts which result from the
volatility in forward curves of commodity prices and changes in the balance of unsettled contracts between periods. Transportation and processing expense reflects unrealized financial hedging gains or losses related to the Companys power
financial derivative contracts. DD&A includes amortization of corporate assets, such as computer equipment, office buildings, furniture and leasehold improvements.
Corporate and Other results include revenues and operating expenses related to the sublease of office space in The Bow office building. Further information on
The Bow office sublease can be found in Note 11 to the Interim Condensed Consolidated Financial Statements.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Other Operating Results
Expenses
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Accretion of asset retirement obligation |
|
$ |
12 |
|
|
$ |
13 |
|
Administrative |
|
|
72 |
|
|
|
102 |
|
Interest |
|
|
125 |
|
|
|
147 |
|
Foreign exchange (gain) loss, net |
|
|
656 |
|
|
|
224 |
|
(Gain) loss on divestitures |
|
|
(14 |
) |
|
|
1 |
|
Other |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
852 |
|
|
$ |
487 |
|
|
|
|
|
|
|
|
|
|
Administrative expense in the first quarter of 2015 decreased from 2014 primarily due to lower long-term compensation costs
due to the decrease in the Encana share price, lower restructuring costs and the lower U.S./Canadian dollar exchange rate. There were no restructuring costs incurred in the first quarter of 2015 compared to $15 million in 2014.
Interest expense in the first quarter of 2015 decreased from 2014 primarily due to lower interest on debt resulting from the long-term debt repayment and
redemption in the first half of 2014.
Foreign exchange gains and losses result from the impact of the fluctuations in the Canadian to U.S. dollar
exchange rate. Foreign exchange losses increased in the first quarter of 2015 primarily due to higher losses on the translation of U.S. dollar long-term debt issued from Canada, intercompany transactions and the revaluation and settlement of other
monetary assets and liabilities.
Gain on divestitures in the first quarter of 2015 primarily includes a gain on the sale of the Encana Place office
building in Calgary.
Income Tax
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Current Income Tax |
|
$ |
16 |
|
|
$ |
16 |
|
Deferred Income Tax (Recovery) |
|
|
(963 |
) |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
Income Tax Expense (Recovery) |
|
$ |
(947 |
) |
|
$ |
28 |
|
|
|
|
|
|
|
|
|
|
Total income tax recovery in the first quarter of 2015 was primarily due to lower net earnings before tax. The net earnings
variances are discussed in the Financial Results section of this MD&A.
Encanas interim income tax expense is determined using the estimated
annual effective income tax rate applied to year-to-date net earnings before tax plus the effect of legislative changes and amounts in respect of prior periods. The Companys effective tax rate for the first quarter of 2015 is higher than 2014
primarily as a result of changes in expected annual earnings. The estimated annual effective income tax rate is impacted by expected annual earnings, statutory rate and other foreign differences, non-taxable capital gains and losses, tax differences
on divestitures and transactions, and partnership tax allocations in excess of funding.
Tax interpretations, regulations and legislation in the various
jurisdictions in which the Company and its subsidiaries operate are subject to change. As a result, there are tax matters under review. The Company believes that the provision for taxes is adequate.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Liquidity and Capital Resources
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Net Cash From (Used In) |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
482 |
|
|
$ |
943 |
|
Investing activities |
|
|
268 |
|
|
|
(446 |
) |
Financing activities |
|
|
968 |
|
|
|
(845 |
) |
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency |
|
|
(26 |
) |
|
|
(56 |
) |
|
|
|
|
|
|
|
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
$ |
1,692 |
|
|
$ |
(404 |
) |
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
$ |
2,030 |
|
|
$ |
2,162 |
|
|
|
|
|
|
|
|
|
|
Operating Activities
Net cash from operating activities in the first
quarter of 2015 of $482 million decreased $461 million from 2014. These changes are primarily a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the first quarter of 2015, the net change in non-cash
working capital was a deficit of $6 million compared to $142 million in 2014.
The Company had a working capital surplus of $748 million at March 31,
2015 compared to $455 million at December 31, 2014. The increase in working capital is primarily due to an increase in cash and cash equivalents and a decrease in accounts payable and accrued liabilities, partially offset by an increase in the
current portion of long-term debt, a decrease in accounts receivable and accrued revenues and a decrease in income tax receivable. At March 31, 2015, working capital included cash and cash equivalents of $2,030 million compared to $338 million
at December 31, 2014. Encana expects that it will continue to meet the payment terms of its suppliers.
Investing Activities
Net cash from investing activities in the first
quarter of 2015 was $268 million compared to net cash used of $446 million in 2014. The change was primarily due to higher proceeds from divestitures, partially offset by higher capital expenditures. Further information on capital expenditures and
acquisitions and divestitures can be found in the Net Capital Investment section of this MD&A.
Financing Activities
Net cash from financing activities in the first
quarter of 2015 was $968 million compared to net cash used of $845 million in 2014. The change was primarily due to proceeds from the issuance of common shares pursuant to the Share Offering in the first quarter of 2015 and the repayment of
long-term debt in the first quarter of 2014.
Long-Term Debt
Encanas long-term debt, excluding the current portion, totaled $5,925 million at March 31, 2015 and $7,340 million at December 31, 2014. The
current portion of long-term debt outstanding was $1,291 million at March 31, 2015. This amount was classified as current as a result of the Companys planned debt redemption in April 2015, as discussed below. There was no current portion
of long-term debt outstanding at December 31, 2014.
On April 6, 2015, the Company used the net proceeds from the Share Offering and cash on
hand to complete the redemption of its $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due January 18, 2018. The note redemptions required an aggregate one-time early interest
payment of approximately $165 million and is expected to save Encana a gross amount of approximately $205 million in future interest expense, based on current foreign exchange and treasury rates.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
During the first quarter of 2015, Encana implemented a U.S. Commercial Paper (U.S. CP) program
which is fully supported by the Companys revolving credit facility. At March 31, 2015, Encana had an outstanding balance of $1,211 million which reflected U.S. CP issuances that had an average term of 38 days and a weighted average
interest rate of 0.66 percent. Management expects these amounts will continue to be supported by the revolving credit facility that has no repayment requirements within the next year. At December 31, 2014, Encana had an outstanding balance of
$1,277 million under the Companys revolving credit facility, which reflected principal obligations related to LIBOR loans maturing at various dates with a weighted average interest rate of 1.62 percent. During the first quarter of 2015, Encana
repaid the outstanding balance relating to LIBOR loans using proceeds from the U.S. CP program and cash on hand. Additional detail on Encanas credit facilities can be found below.
Encana has the flexibility to refinance maturing long-term debt or repay debt maturities from existing sources of liquidity. Encanas primary sources of
liquidity include cash and cash equivalents, revolving bank credit facilities, working capital, operating cash flow and proceeds from asset divestitures.
Credit Facilities and Shelf Prospectus
Encana maintains
two revolving bank credit facilities which remain committed through June 2018. At March 31, 2015, Encana had available unused committed revolving bank credit facilities of $2.6 billion as follows:
|
|
|
A committed revolving bank credit facility for C$3.5 billion ($2.8 billion) for Encana, of which $1.6 billion remained unused. |
|
|
|
A committed revolving bank credit facility for a U.S. subsidiary for $1.0 billion, all of which remained unused. |
On June 27, 2014, Encana filed a short form base shelf prospectus, whereby the Company may issue from time to time up to $6.0 billion, or the equivalent
in foreign currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants and units in Canada and/or the U.S. On March 5, 2015, the Company filed a prospectus supplement to the base shelf prospectus for the
issuance of 85,616,500 common shares of Encana and granted an over-allotment option for up to an additional 12,842,475 common shares of Encana at a price of C$14.60 per common share, pursuant to an underwriting agreement. The Share Offering of
98,458,975 common shares of Encana was completed during March 2015 for aggregate gross proceeds of approximately C$1.44 billion ($1.13 billion). After deducting underwriters fees and costs of the Share Offering, the net proceeds received were
approximately C$1.39 billion ($1.09 billion). At March 31, 2015, $4.9 billion, or the equivalent in foreign currencies, remained accessible under the shelf prospectus, the availability of which is dependent upon market conditions. The shelf
prospectus expires in July 2016.
Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial
covenants under its credit facility agreements. Management monitors Debt to Adjusted Capitalization as a proxy for Encanas financial covenant under its credit facility agreements which require debt to adjusted capitalization to be less than 60
percent. The definitions used in the covenant under the credit facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Companys January 1,
2012 adoption of U.S. GAAP. Debt to Adjusted Capitalization was 29 percent at March 31, 2015 and 30 percent at December 31, 2014.
Outstanding Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions) |
|
December 31, 2014 |
|
|
March 31, 2015 |
|
|
May 8, 2015 |
|
|
|
|
|
Common Shares Outstanding |
|
|
741.2 |
|
|
|
840.9 |
|
|
|
840.9 |
|
Stock Options with TSARs attached: |
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
|
21.3 |
|
|
|
20.8 |
|
|
|
20.6 |
|
Exercisable |
|
|
10.0 |
|
|
|
11.2 |
|
|
|
11.1 |
|
Pursuant to the Share Offering, Encana issued approximately 98.4 million common shares during the first quarter of 2015.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
During the first quarter of 2015, Encana issued 1,267,680 common shares under the Companys dividend
reinvestment plan (DRIP) compared with 54,472 common shares in 2014. The number of common shares issued under the DRIP increased in the first quarter of 2015 as a result of Encanas February 25, 2015 announcement that,
effective with the dividend payable on March 31, 2015, any future dividends in conjunction with the DRIP will be issued from its treasury with a two percent discount to the average market price of the common shares unless otherwise announced by
the Company via news release.
A Tandem Stock Appreciation Right (TSAR) gives the option holder the right to receive a cash payment equal to
the excess of the market price of Encanas common shares at the time of exercise over the original grant price.
Dividends
Encana pays quarterly dividends to shareholders at the discretion of the Board.
|
|
|
|
|
|
|
|
|
|
|
As at March 31 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
Dividend Payments |
|
$ |
52 |
|
|
$ |
52 |
|
Dividend Payments ($/share) |
|
$ |
0.07 |
|
|
$ |
0.07 |
|
The dividends paid in the first quarter of 2015 included $14 million in common shares issued in lieu of cash dividends under
the DRIP compared to $1 million for 2014. Common shares issued in the Share Offering were not eligible to receive the dividend that was paid during the first quarter of 2015.
On May 11, 2015, the Board declared a dividend of $0.07 per share payable on June 30, 2015 to common shareholders of record as of June 15,
2015.
Capital Structure
The Companys capital
structure consists of total shareholders equity plus long-term debt, including the current portion. The Companys objectives when managing its capital structure are to maintain financial flexibility to preserve Encanas access to
capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Encana has a long-standing practice of maintaining capital discipline and managing and adjusting its capital
structure according to market conditions to maintain flexibility while achieving the Companys objectives.
To manage the capital structure, the
Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or repay existing debt. In managing its capital structure, the Company monitors the following non-GAAP financial metrics as indicators of
its overall financial strength, which are defined in the Non-GAAP Measures section of this MD&A.
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt to Debt Adjusted Cash Flow |
|
|
2.6x |
|
|
|
2.1x |
|
Debt to Adjusted Capitalization |
|
|
29 |
% |
|
|
30 |
% |
Subsequent to the debt redemption completed on April 6, 2015, Debt to Debt Adjusted Cash Flow was approximately 2.1x and
Debt to Adjusted Capitalization was approximately 26 percent.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Commitments and Contingencies
Commitments
The following table outlines the
Companys commitments at March 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Payments |
|
($ millions, undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
598 |
|
|
$ |
787 |
|
|
$ |
779 |
|
|
$ |
798 |
|
|
$ |
674 |
|
|
$ |
3,085 |
|
|
$ |
6,721 |
|
Drilling and Field Services |
|
|
164 |
|
|
|
128 |
|
|
|
90 |
|
|
|
47 |
|
|
|
14 |
|
|
|
16 |
|
|
|
459 |
|
Operating Leases |
|
|
24 |
|
|
|
27 |
|
|
|
22 |
|
|
|
21 |
|
|
|
8 |
|
|
|
20 |
|
|
|
122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments |
|
$ |
786 |
|
|
$ |
942 |
|
|
$ |
891 |
|
|
$ |
866 |
|
|
$ |
696 |
|
|
$ |
3,121 |
|
|
$ |
7,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the Commitments disclosed above, Encana has significant development commitments with joint venture partners, a
portion of which may be satisfied by the Drilling and Field Services commitments included in the table above.
Included in Transportation and Processing
in the table above are certain commitments associated with midstream service agreements with VMLP. Additional information can be found in Note 15 to the Interim Condensed Consolidated Financial Statements.
Further to the Commitments disclosed above, Encana also has obligations related to its risk management program and to fund its defined benefit pension and
other post-employment benefit plans. Further information can be found in Note 20 to the Interim Condensed Consolidated Financial Statements regarding the Companys risk management program.
Contractual obligations arising from long-term debt, asset retirement obligations, The Bow office building and capital leases are recognized on the
Companys balance sheet. Further information can be found in the note disclosures to the Interim Condensed Consolidated Financial Statements.
The
Company expects to fund its 2015 commitments and obligations from Cash Flow and cash and cash equivalents.
Contingencies
Encana is involved in various legal claims and actions arising in the course of the Companys operations. Although the outcome of these claims cannot be
predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encanas financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of
a material adverse impact on the Companys consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable and the amount
can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Risk Management
Encanas business, prospects, financial condition, results of operations and cash flows, and in some cases its reputation, are impacted by risks that can
be categorized as follows:
|
|
|
environmental, regulatory, reputational and safety risks. |
Encana aims to strengthen its position as a leading
North American energy producer and grow shareholder value through a disciplined focus on generating profitable growth. Encana continues to focus on developing a balanced portfolio of low-risk and low-cost long-life plays, which allows the Company to
respond well to market uncertainties. Management adjusts financial and operational risk strategies to proactively respond to changing economic conditions and to mitigate or reduce risk.
Issues that can affect Encanas reputation are generally strategic or emerging issues that can be identified early and then appropriately managed, but
can also include unforeseen issues that must be managed on a more urgent basis. Encana takes a proactive approach to the identification and management of issues that affect the Companys reputation and has established appropriate policies,
procedures, guidelines and responsibilities for identifying and managing these issues.
Financial Risks
Encana defines financial risks as the risk of loss or lost opportunity resulting from financial management and market conditions that could have an impact on
Encanas business.
Financial risks include, but are not limited to:
|
|
|
market pricing of natural gas and liquids; |
|
|
|
foreign exchange rates; and |
Encana partially mitigates its exposure to financial risks through the use of various
financial instruments and physical contracts. The use of derivative financial instruments is governed under formal policies and is subject to limits established by the Board. All derivative financial agreements are with major global financial
institutions or with corporate counterparties having investment grade credit ratings. Encana has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and
specifically ties their use to the mitigation of financial risk in order to support capital plans and strategic objectives.
To partially mitigate
commodity price risk, the Company may enter into transactions that fix, set a floor or set a floor and cap on prices. To help protect against regional price differentials, Encana executes transactions to manage the price differentials between its
production areas and various sales points. Further information, including the details of Encanas financial instruments as at March 31, 2015, is disclosed in Note 20 to the Interim Condensed Consolidated Financial Statements.
Counterparty credit risks are regularly and proactively managed. A substantial portion of Encanas credit exposure is with customers in the oil and gas
industry or financial institutions. This credit exposure is mitigated through the use of Board-approved credit policies governing the Companys credit portfolio, including credit practices that limit transactions and grant payment terms
according to industry standards and counterparties credit quality.
The Company manages liquidity risk using cash and debt management programs. The
Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
facilities and debt and equity capital markets. Encana closely monitors the Companys ability to access cost-effective credit and ensures that sufficient liquidity is in place to fund
capital expenditures and dividend payments. The Company minimizes its liquidity risk by managing its capital structure which may include adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, issuing new debt or
repaying existing debt.
Operational Risks
Operational risks are defined as the risk of loss or lost opportunity resulting from the following:
|
|
|
capital activities, including the ability to complete projects; and |
|
|
|
reserves and resources replacement. |
The Companys ability to operate, generate cash flows, complete
projects, and value reserves and resources is subject to financial risks, including commodity prices mentioned above, continued market demand for its products and other risk factors outside of its control. These factors include: general business and
market conditions; economic recessions and financial market turmoil; the overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Companys securities in particular; the
ability to secure and maintain cost-effective financing for its commitments; legislative, environmental and regulatory matters; unexpected cost increases; royalties; taxes; volatility in natural gas and liquids prices; partner funding for their
share of joint venture and partnership commitments; the availability of drilling and other equipment; the ability to access lands; the ability to access water for hydraulic fracturing operations; weather; the availability of processing capacity; the
availability and proximity of take-away capacity; technology failures; the ability to integrate new assets; cyber-attacks; accidents; the availability of skilled labour; and reservoir quality. If Encana fails to acquire or find additional natural
gas and liquids reserves and resources, its reserves, resources and production will decline materially from their current levels and, therefore, its cash flows are highly dependent upon successfully exploiting current reserves and resources and
acquiring, discovering or developing additional reserves and resources. To mitigate these risks, as part of the capital approval process, the Companys projects are evaluated on a fully risked basis, including geological risk, engineering risk
and reliance on third party service providers.
When making operating and investing decisions, Encanas highly disciplined, dynamic and centrally
controlled capital allocation program ensures investment dollars are directed in a manner that is consistent with the Companys strategy. Encana also mitigates operational risks through a number of other policies, systems and processes as well
as by maintaining a comprehensive insurance program.
Environmental, Regulatory, Reputational and Safety Risks
The Company is committed to safety in its operations and has high regard for the environment and stakeholders, including the public and regulators. The
Companys business is subject to all of the operating risks normally associated with the exploration for, development of and production of natural gas, oil and NGLs and the operation of midstream facilities. When assessing the materiality of
environmental risk factors, Encana takes into account a number of qualitative and quantitative factors, including, but not limited to, the financial, operational, reputational and regulatory aspects of each identified risk factor. These risks are
managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, Encana maintains a system that identifies, assesses and controls safety, security and environmental
risk and requires regular reporting to the Executive Leadership Team and the Board. The Corporate Responsibility, Environment, Health and Safety Committee of Encanas Board provides recommended environmental policies for approval by
Encanas Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and audits, are designed to provide
assurance that environmental and regulatory standards are met. Emergency response plans are in place to provide guidance during times of crisis. Contingency plans are in place for a timely response to environmental events and remediation/reclamation
strategies are utilized to restore the environment.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Encanas operations are subject to regulation and intervention by governments that can affect or
prohibit the drilling, completion, including hydraulic fracturing and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Changes in government regulation could impact the
Companys existing and planned projects as well as impose a cost of compliance.
In the state of Colorado, several cities have passed local
ordinances limiting or banning certain oil and gas activities, including hydraulic fracturing. These local rule-making initiatives have not significantly impacted the Companys operations or development plans in the state to date. Encana
continues to work with state and local governments, academics and industry leaders to respond to hydraulic fracturing related concerns in Colorado. The Company recognizes that additional hydraulic fracturing ballot and/or local rule-making limiting
or restricting oil and gas development activities are a possibility in the future and will continue to monitor and respond to these developments in 2015.
The U.S. federal government has noted climate change action as a priority for the current administration. On January 14, 2015, the Environmental
Protection Agency (EPA) outlined a series of steps to address methane and volatile organic compound emissions from the oil and gas industry, including a new goal to reduce oil and gas methane emissions by 40 to 45 percent from 2012
levels by 2025. The reductions will be achieved through regulatory and voluntary measures which have not yet been announced. The EPA plans to propose this new rule and guidance in late summer 2015 with a final rule and guidance expected in 2016.
A comprehensive discussion of Encanas risk management is provided in the Companys annual MD&A for the year ended December 31, 2014.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Controls and Procedures
Internal Control over Financial Reporting
Management is
responsible for establishing and maintaining adequate internal control over the Companys financial reporting, which is a process designed by, or designed under the supervision of the Chief Executive Officer and Chief Financial Officer, and
effected by the Board, Management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
Except for changes relating to the continuing integration of Athlon Energy Inc. (Athlon), as discussed below, there have been no changes in the
Companys internal control over financial reporting during the three months ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, the effectiveness of the internal control over financial
reporting.
In accordance with Section 3.3(1) of National Instrument 52-109 and Rules 13a-15(f) and 15d-15(f) under the United States Securities and
Exchange Act of 1934, as amended, Management has limited the scope and design and subsequent evaluation of internal controls over financial reporting to exclude the controls, policies and procedures of Athlon, acquired through a business combination
on November 13, 2014. Summary financial information related to Athlons operations included in Encanas Interim Condensed Consolidated Financial Statements for the period ended March 31, 2015 is as follows:
|
|
|
|
|
($ millions) |
|
|
|
Revenues |
|
$ |
55 |
|
Net Earnings |
|
|
25 |
|
Current Assets |
|
|
61 |
|
Non-Current Assets |
|
|
3,059 |
|
Current Liabilities |
|
|
41 |
|
Non-Current Liabilities |
|
|
168 |
|
Limitations of the Effectiveness of Controls
The Companys control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated
Financial Statements. Control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and
presentation and should not be expected to prevent all errors or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Accounting Policies and Estimates
Critical Accounting Estimates
Refer to the annual MD&A for the year ended December 31, 2014 for a comprehensive discussion of Encanas Critical Accounting Policies and
Estimates.
Recent Accounting Pronouncements
Changes in Accounting Policies and Practices
On January 1, 2015, Encana adopted Accounting Standard Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of
Disposals of Components of an Entity as issued by the Financial Accounting Standards Board (FASB). The update amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only
disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments have been applied prospectively and have not had a material impact on the Companys Interim Condensed Consolidated Financial
Statements.
New Standards Issued Not Yet Adopted
As
of January 1, 2016, Encana will be required to adopt the following pronouncements issued by the FASB:
|
|
|
ASU 2014-12, Compensation Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period. The
update requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied prospectively and are not expected to have a material
impact on the Companys Consolidated Financial Statements. |
|
|
|
ASU 2015-02, Amendments to the Consolidation Analysis. The update requires limited partnerships and similar entities to be evaluated under the variable interest and voting interest models, eliminate the
presumption that a general partner should consolidate a limited partnership, and simplify the identification of variable interests and related effect on the primary beneficiary criterion when fees are paid to a decision maker. The amendments can be
applied using either a full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the amendments on the Companys Consolidated Financial Statements.
|
|
|
|
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs to be presented on the balance sheet as a deduction from the carrying amount of the related liability.
Previously, debt issuance costs were presented as a deferred charge within assets. The amendments will be applied retrospectively. As at March 31, 2015, $43 million of debt issuance costs were presented in Other Assets on the Companys
interim Condensed Consolidated Balance Sheet ($48 million as at December 31, 2014). |
As of January 1, 2017, Encana will be
required to adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, Revenue
Recognition, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that
reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana
is currently assessing the potential impact of the standard on the Companys Consolidated Financial Statements.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Non-GAAP Measures
Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These
measures may not be comparable to similar measures presented by other issuers. These measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the
Companys liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings; Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted
Cash Flow; and Debt to Adjusted Capitalization. Managements use of these measures is discussed further below.
Cash Flow and Free Cash Flow
Cash Flow is a non-GAAP measure commonly
used in the oil and gas industry and by Encana to assist Management and investors in measuring the Companys ability to finance capital programs and meet financial obligations. Cash Flow is defined as cash from operating activities excluding
net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets.
Free Cash Flow is a non-GAAP measure
defined as Cash Flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2013 |
|
($ millions) |
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
$ |
482 |
|
|
$ |
261 |
|
|
$ |
696 |
|
|
$ |
767 |
|
|
$ |
943 |
|
|
$ |
462 |
|
|
$ |
935 |
|
|
$ |
554 |
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
(7 |
) |
|
|
(15 |
) |
|
|
(11 |
) |
|
|
(8 |
) |
|
|
(9 |
) |
|
|
(21 |
) |
|
|
(15 |
) |
|
|
(22 |
) |
Net change in non-cash working capital |
|
|
(6 |
) |
|
|
(141 |
) |
|
|
155 |
|
|
|
119 |
|
|
|
(142 |
) |
|
|
(183 |
) |
|
|
300 |
|
|
|
(81 |
) |
Cash tax on sale of assets |
|
|
|
|
|
|
40 |
|
|
|
(255 |
) |
|
|
|
|
|
|
|
|
|
|
(11 |
) |
|
|
(10 |
) |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow |
|
$ |
495 |
|
|
$ |
377 |
|
|
$ |
807 |
|
|
$ |
656 |
|
|
$ |
1,094 |
|
|
$ |
677 |
|
|
$ |
660 |
|
|
$ |
665 |
|
Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital investment |
|
|
736 |
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
717 |
|
|
|
641 |
|
|
|
639 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash Flow |
|
$ |
(241 |
) |
|
$ |
(480 |
) |
|
$ |
209 |
|
|
$ |
96 |
|
|
$ |
583 |
|
|
$ |
(40 |
) |
|
$ |
19 |
|
|
$ |
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Operating Earnings
Operating Earnings is a non-GAAP measure that
adjusts Net Earnings (Loss) Attributable to Common Shareholders by non-operating items that Management believes reduces the comparability of the Companys underlying financial performance between periods. Operating Earnings is commonly used in
the oil and gas industry and by Encana to provide investors with information that is more comparable between periods.
Operating Earnings is defined as
Net Earnings (Loss) Attributable to Common Shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Companys financial performance between periods. These after-tax items may include, but
are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of
income taxes calculated using the estimated annual effective income tax rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2013 |
|
($ millions) |
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
$ |
(1,707 |
) |
|
$ |
198 |
|
|
$ |
2,807 |
|
|
$ |
271 |
|
|
$ |
116 |
|
|
$ |
(251 |
) |
|
$ |
188 |
|
|
$ |
730 |
|
|
|
|
|
|
|
|
|
|
After-tax (addition) / deduction: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
|
(98 |
) |
|
|
341 |
|
|
|
160 |
|
|
|
8 |
|
|
|
(203 |
) |
|
|
(209 |
) |
|
|
(89 |
) |
|
|
332 |
|
Impairments |
|
|
(1,222 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
Restructuring charges |
|
|
|
|
|
|
(4 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(10 |
) |
|
|
(64 |
) |
|
|
|
|
|
|
|
|
Non-operating foreign exchange gain (loss) |
|
|
(508 |
) |
|
|
(151 |
) |
|
|
(218 |
) |
|
|
156 |
|
|
|
(194 |
) |
|
|
(124 |
) |
|
|
105 |
|
|
|
(162 |
) |
Gain (loss) on divestitures |
|
|
10 |
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax adjustments |
|
|
102 |
|
|
|
(12 |
) |
|
|
190 |
|
|
|
(194 |
) |
|
|
8 |
|
|
|
(80 |
) |
|
|
38 |
|
|
|
313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings |
|
$ |
9 |
|
|
$ |
35 |
|
|
$ |
281 |
|
|
$ |
171 |
|
|
$ |
515 |
|
|
$ |
226 |
|
|
$ |
150 |
|
|
$ |
247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Upstream Operating Cash Flow, excluding Hedging
Upstream Operating Cash Flow, excluding Hedging is
a non-GAAP measure that adjusts the Canadian and USA Operations revenues, net of royalties for production and mineral taxes, transportation and processing expense, operating expense and the impacts of realized hedging. Management monitors Upstream
Operating Cash Flow, excluding Hedging as it reflects operating performance and measures the Companys portfolio transition to higher margin production. Upstream Operating Cash Flow, excluding Hedging is reconciled to GAAP measures in the
Results of Operations section of this MD&A. The table below totals Upstream Operating Cash Flow for Encana.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2013 |
|
($ millions) |
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
413 |
|
|
$ |
341 |
|
|
$ |
477 |
|
|
$ |
447 |
|
|
$ |
881 |
|
|
$ |
526 |
|
|
$ |
406 |
|
|
$ |
383 |
|
USA Operations |
|
|
289 |
|
|
|
480 |
|
|
|
505 |
|
|
|
353 |
|
|
|
434 |
|
|
|
375 |
|
|
|
388 |
|
|
|
405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
702 |
|
|
$ |
821 |
|
|
$ |
982 |
|
|
$ |
800 |
|
|
$ |
1,315 |
|
|
$ |
901 |
|
|
$ |
794 |
|
|
$ |
788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Hedging Gain (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
156 |
|
|
$ |
49 |
|
|
$ |
19 |
|
|
$ |
(49 |
) |
|
$ |
(75 |
) |
|
$ |
90 |
|
|
$ |
95 |
|
|
$ |
21 |
|
USA Operations |
|
|
92 |
|
|
|
78 |
|
|
|
11 |
|
|
|
(49 |
) |
|
|
(65 |
) |
|
|
83 |
|
|
|
77 |
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
248 |
|
|
$ |
127 |
|
|
$ |
30 |
|
|
$ |
(98 |
) |
|
$ |
(140 |
) |
|
$ |
173 |
|
|
$ |
172 |
|
|
$ |
51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow, excluding Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
257 |
|
|
$ |
292 |
|
|
$ |
458 |
|
|
$ |
496 |
|
|
$ |
956 |
|
|
$ |
436 |
|
|
$ |
311 |
|
|
$ |
362 |
|
USA Operations |
|
|
197 |
|
|
|
402 |
|
|
|
494 |
|
|
|
402 |
|
|
|
499 |
|
|
|
292 |
|
|
|
311 |
|
|
|
375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
454 |
|
|
$ |
694 |
|
|
$ |
952 |
|
|
$ |
898 |
|
|
$ |
1,455 |
|
|
$ |
728 |
|
|
$ |
622 |
|
|
$ |
737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Netback
Operating Netback is a common metric used in the
oil and gas industry to measure operating performance by product. Operating Netbacks are calculated by determining product revenues, net of royalties and deducting costs associated with delivering the product to market, including production and
mineral taxes, transportation and processing expense and operating expense. The Operating Netback calculation is shown in the Results of Operations section of this MD&A.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Debt to Debt Adjusted Cash Flow
Debt to Debt Adjusted Cash Flow is a non-GAAP
measure monitored by Management as an indicator of the Companys overall financial strength. Debt Adjusted Cash Flow is a non-GAAP measure defined as Cash Flow on a trailing 12-month basis excluding interest expense after tax.
|
|
|
|
|
|
|
|
|
($ millions) |
|
March 31, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt |
|
$ |
7,216 |
|
|
$ |
7,340 |
|
|
|
|
Cash Flow |
|
|
2,335 |
|
|
|
2,934 |
|
Interest Expense, after tax |
|
|
470 |
|
|
|
486 |
|
|
|
|
|
|
|
|
|
|
Debt Adjusted Cash Flow |
|
$ |
2,805 |
|
|
$ |
3,420 |
|
|
|
|
|
|
|
|
|
|
Debt to Debt Adjusted Cash Flow |
|
|
2.6x |
|
|
|
2.1x |
|
|
|
|
|
|
|
|
|
|
Debt to Adjusted Capitalization
Debt to Adjusted Capitalization is a non-GAAP
measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for Encanas financial covenant under its credit
facility agreements which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders equity and an equity adjustment for cumulative historical ceiling test impairments recorded
as at December 31, 2011 in conjunction with the Companys January 1, 2012 adoption of U.S. GAAP.
|
|
|
|
|
|
|
|
|
($ millions) |
|
March 31, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt |
|
$ |
7,216 |
|
|
$ |
7,340 |
|
Total Shareholders Equity |
|
|
9,517 |
|
|
|
9,685 |
|
Equity Adjustment for Impairments at December 31, 2011 |
|
|
7,746 |
|
|
|
7,746 |
|
|
|
|
|
|
|
|
|
|
Adjusted Capitalization |
|
$ |
24,479 |
|
|
$ |
24,771 |
|
|
|
|
|
|
|
|
|
|
Debt to Adjusted Capitalization |
|
|
29 |
% |
|
|
30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Advisory
Forward-Looking Statements
In the interest of providing Encana shareholders and potential investors with information regarding the Company and its subsidiaries, including
Managements assessment of Encanas and its subsidiaries future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively referred to herein as
forward-looking statements) within the meaning of the safe harbour provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as anticipate,
believe, expect, plan, intend, forecast, target, project, objective, strategy, strives, agreed to or similar words
suggesting future outcomes or statements regarding an outlook. Forward-looking statements in this document include, but are not limited to, statements with respect to:
|
|
achieving the Companys focus on developing its strong portfolio of resource plays producing natural gas, oil and NGLs |
|
|
commitment to growing long-term shareholder value through a disciplined focus on generating profitable growth |
|
|
pursuing its key business objectives of balancing its commodity portfolio, focusing capital investments in strategic high return, scalable projects, maintaining portfolio flexibility, maximizing profitability through
operating efficiencies, reducing costs and preserving balance sheet strength |
|
|
anticipated revenues and operating expenses |
|
|
improving operating efficiencies, fostering technological innovation, lowering cost structures and the success of the resource play hub model |
|
|
the anticipated proceeds from various joint venture, partnership and other agreements entered into by the Company, including their successful implementation, expected future benefits and the Companys ability to
fund future development costs associated with those agreements |
|
|
statements with respect to future ceiling test impairments |
|
|
anticipated oil, natural gas and NGLs prices |
|
|
projections contained in the 2015 Corporate Guidance (including estimates of cash flow including per share amounts, natural gas, oil and NGLs production, capital investment and its allocation, operating costs,
sensitivities on price and their impact on cash flow and operating earnings, assumptions regarding oil, natural gas and NGLs prices and foreign exchange rates) |
|
|
estimates of reserves and resources |
|
|
projections relating to the adequacy of the Companys provision for taxes and legal claims
|
|
|
the flexibility of capital spending plans and the source of funding therefor |
|
|
expected future interest expense savings |
|
|
anticipated access to capital markets and ability to meet financial obligations and finance growth |
|
|
the benefits of the Companys risk management program, including the impact of derivative financial instruments |
|
|
projections that the Company has access to cash and cash equivalents and a range of funding at competitive rates |
|
|
the Companys ability to meet payment terms of its suppliers and be in compliance with all financial covenants under its credit facility agreements |
|
|
anticipated debt repayments and the ability to make such repayments |
|
|
expectations surrounding environmental legislation including regulations relating to carbon, air quality, water, land and hydraulic fracturing and the impact such regulations could have on the Company |
|
|
anticipated flexibility to refinance maturing long-term debt or repay debt maturities from existing sources of liquidity |
|
|
anticipated cash and cash equivalents |
|
|
expectation to fund 2015 commitments from Cash Flow, cash and cash equivalents |
|
|
the anticipated effect of the Companys risk mitigation policies, systems, processes and insurance program |
|
|
the Companys ability to manage its Debt to Debt Adjusted Cash Flow and Debt to Adjusted Capitalization ratios |
|
|
the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company and its financial statements
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance
that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the
possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the Companys actual performance and financial results in future periods to differ materially from any estimates or
projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things:
|
|
commodity price volatility |
|
|
assumptions based upon the Companys current guidance |
|
|
fluctuations in currency and interest rates |
|
|
risk that the Company may not conclude divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements (such transactions may include third party capital
investments, farm-outs or partnerships, which Encana may refer to from time to time as partnerships or joint ventures and the funds received in respect thereof which Encana may refer to from time to time as
proceeds, deferred purchase price and/or carry capital, regardless of the legal form) as a result of various conditions not being met |
|
|
risks inherent in the Companys and its subsidiaries marketing operations, including credit risks |
|
|
imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent
resources, including future net revenue estimates |
|
|
potential disruption or unexpected technical difficulties in developing new facilities |
|
|
risks associated with technology |
|
|
the Companys ability to acquire or find additional reserves |
|
|
availability of hedges at attractive prices and hedging activities resulting in realized and unrealized losses
|
|
|
business interruption and casualty losses |
|
|
risk of the Company not operating all of its properties and assets |
|
|
downgrade in credit rating and its adverse effects |
|
|
liability for indemnification obligations to third parties |
|
|
variability of dividends to be paid |
|
|
the Companys ability to generate sufficient cash flow from operations to meet its current and future obligations |
|
|
the Companys ability to access external sources of debt and equity capital |
|
|
the timing and the costs of well and pipeline construction |
|
|
the Companys ability to secure adequate product transportation |
|
|
changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations |
|
|
political and economic conditions in the countries in which the Company operates; terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the Company
|
|
|
risk arising from price basis differential |
|
|
other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Encana
|
Although Encana believes that the
expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. Furthermore,
the forward-looking statements contained in this document are made as of the date hereof and, except as required by law, Encana undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements
contained in this document are expressly qualified by this cautionary statement.
Forward-looking information respecting anticipated 2015 cash flow for
Encana is based upon, among other things, achieving average production for 2015 of between 1,600 MMcf/d and 1,700 MMcf/d of natural gas and 130 Mbbls/d to 150 Mbbls/d of liquids, commodity prices for natural gas and liquids based on NYMEX $3.00 per
MMBtu and WTI of $50 per bbl, an estimated U.S./Canadian dollar exchange rate of 0.80 and a weighted average number of outstanding shares for Encana of approximately 821 million.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Assumptions relating to forward-looking statements generally include Encanas current expectations and
projections made in light of, and generally consistent with, its historical experience and its perception of historical trends.
Encana is required to
disclose events and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete
that Encana has previously disclosed to the public and the expected differences thereto. Such disclosure can be found in Encanas news release dated May 12, 2015, which is available on Encanas website at www.encana.com, on
SEDAR at www.sedar.com and EDGAR at www.sec.gov.
Oil and Gas Information
National Instrument 51-101 (NI 51-101)
of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. The Canadian protocol disclosure is contained in Appendix A and under Narrative Description of
the Business in the Companys Annual Information Form (AIF). Encana obtained an exemption dated January 4, 2011 from certain requirements of NI 51-101 to permit it to provide certain disclosure prepared in accordance with
U.S. disclosure requirements, in addition to the Canadian protocol disclosure. The Companys U.S. protocol disclosure is included in Note 26 (unaudited) to the Companys Consolidated Financial Statements for the year ended
December 31, 2014 and in Appendix D of the AIF.
Further, Encana obtained an exemption dated January 21, 2015 from certain requirements of NI
51-101 to permit it to use the definition of product type contained in the amendments to NI 51-101, published by the securities regulatory authority in each of the jurisdictions of Canada on December 4, 2014 that are anticipated to
come into force on July 1, 2015, as it relates to its Canadian protocol disclosure contained in Appendix A of the AIF.
A description of the primary
differences between the disclosure requirements under the Canadian standards and under the U.S. standards is set forth under the heading Reserves and Other Oil and Gas Information in the AIF.
Natural Gas, Oil and NGLs Conversions
In this document,
certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of 6:1 is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent value equivalency at the wellhead.
Given that the value ratio based on the current price of natural gas as
compared to oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Play and Resource Play
Play is a term used by Encana
which encompasses resource plays, geological formations and conventional plays. Resource play is a term used by Encana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which, when
compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate.
Additional
Information
Further information regarding
Encana Corporation, including its AIF, can be accessed under the Companys public filings found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov and on the Companys website at www.encana.com
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Condensed Consolidated Statement of Earnings (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
($ millions, except per share amounts) |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
Revenues, Net of Royalties |
|
|
(Note 3) |
|
|
$ |
1,249 |
|
|
$ |
1,892 |
|
|
|
|
|
Expenses |
|
|
(Note 3) |
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
19 |
|
|
|
47 |
|
Transportation and processing |
|
|
|
|
|
|
340 |
|
|
|
379 |
|
Operating |
|
|
|
|
|
|
189 |
|
|
|
189 |
|
Purchased product |
|
|
|
|
|
|
121 |
|
|
|
228 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
466 |
|
|
|
418 |
|
Impairments |
|
|
(Note 9) |
|
|
|
1,916 |
|
|
|
|
|
Accretion of asset retirement obligation |
|
|
(Note 12) |
|
|
|
12 |
|
|
|
13 |
|
Administrative |
|
|
(Note 16) |
|
|
|
72 |
|
|
|
102 |
|
Interest |
|
|
(Note 6) |
|
|
|
125 |
|
|
|
147 |
|
Foreign exchange (gain) loss, net |
|
|
(Note 7) |
|
|
|
656 |
|
|
|
224 |
|
(Gain) loss on divestitures |
|
|
(Note 5) |
|
|
|
(14 |
) |
|
|
1 |
|
Other |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,903 |
|
|
|
1,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
(2,654 |
) |
|
|
144 |
|
Income tax expense (recovery) |
|
|
(Note 8) |
|
|
|
(947 |
) |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
$ |
(1,707 |
) |
|
$ |
116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
|
(Note 13) |
|
|
$ |
(2.25 |
) |
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidated Statement of Comprehensive Income (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
($ millions) |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
$ |
(1,707 |
) |
|
$ |
116 |
|
Other Comprehensive Income, Net of Tax |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
|
|
(Note 14) |
|
|
|
478 |
|
|
|
24 |
|
Pension and other post-employment benefit plans |
|
|
(Notes 14, 18) |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income |
|
|
|
|
|
|
479 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss) |
|
|
|
|
|
$ |
(1,228 |
) |
|
$ |
140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Condensed Consolidated Balance Sheet (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
$ |
2,030 |
|
|
$ |
338 |
|
Accounts receivable and accrued revenues |
|
|
|
|
|
|
940 |
|
|
|
1,307 |
|
Risk management |
|
|
(Note 20) |
|
|
|
607 |
|
|
|
707 |
|
Income tax receivable |
|
|
|
|
|
|
384 |
|
|
|
509 |
|
Deferred income taxes |
|
|
|
|
|
|
101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,062 |
|
|
|
2,861 |
|
Property, Plant and Equipment, at cost: |
|
|
(Note 9) |
|
|
|
|
|
|
|
|
|
Natural gas and oil properties, based on full cost accounting |
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
|
|
|
|
41,086 |
|
|
|
42,615 |
|
Unproved properties |
|
|
|
|
|
|
5,984 |
|
|
|
6,133 |
|
Other |
|
|
|
|
|
|
2,446 |
|
|
|
2,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
|
49,516 |
|
|
|
51,459 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
|
|
|
|
(34,354 |
) |
|
|
(33,444 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
(Note 3) |
|
|
|
15,162 |
|
|
|
18,015 |
|
Cash in Reserve |
|
|
|
|
|
|
44 |
|
|
|
73 |
|
Other Assets |
|
|
|
|
|
|
356 |
|
|
|
394 |
|
Risk Management |
|
|
(Note 20) |
|
|
|
13 |
|
|
|
65 |
|
Deferred Income Taxes |
|
|
|
|
|
|
349 |
|
|
|
296 |
|
Goodwill |
|
|
(Notes 3, 4) |
|
|
|
2,850 |
|
|
|
2,917 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 3) |
|
|
$ |
22,836 |
|
|
$ |
24,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
$ |
1,903 |
|
|
$ |
2,243 |
|
Income tax payable |
|
|
|
|
|
|
16 |
|
|
|
15 |
|
Risk management |
|
|
(Note 20) |
|
|
|
13 |
|
|
|
20 |
|
Current portion of long-term debt |
|
|
(Note 10) |
|
|
|
1,291 |
|
|
|
|
|
Deferred income taxes |
|
|
|
|
|
|
91 |
|
|
|
128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,314 |
|
|
|
2,406 |
|
Long-Term Debt |
|
|
(Note 10) |
|
|
|
5,925 |
|
|
|
7,340 |
|
Other Liabilities and Provisions |
|
|
(Note 11) |
|
|
|
2,225 |
|
|
|
2,484 |
|
Risk Management |
|
|
(Note 20) |
|
|
|
12 |
|
|
|
7 |
|
Asset Retirement Obligation |
|
|
(Note 12) |
|
|
|
773 |
|
|
|
870 |
|
Deferred Income Taxes |
|
|
|
|
|
|
1,070 |
|
|
|
1,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,319 |
|
|
|
14,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies |
|
|
(Note 21) |
|
|
|
|
|
|
|
|
|
Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
Share capital - authorized unlimited common shares, without par value 2015 issued and outstanding: 840.9 million shares (2014:
741.2 million shares) |
|
|
(Note 13) |
|
|
|
3,562 |
|
|
|
2,450 |
|
Paid in surplus |
|
|
(Note 17) |
|
|
|
1,358 |
|
|
|
1,358 |
|
Retained earnings |
|
|
|
|
|
|
3,429 |
|
|
|
5,188 |
|
Accumulated other comprehensive income |
|
|
(Note 14) |
|
|
|
1,168 |
|
|
|
689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Shareholders Equity |
|
|
|
|
|
|
9,517 |
|
|
|
9,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
22,836 |
|
|
$ |
24,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Condensed Consolidated Statement of Changes in Shareholders Equity (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2015 ($ millions) |
|
|
|
|
Share Capital |
|
|
Paid in Surplus |
|
|
Retained Earnings |
|
|
Accumulated Other Comprehensive Income |
|
|
Total Shareholders Equity |
|
|
|
|
|
|
|
|
Balance, December 31, 2014 |
|
|
|
|
|
$ |
2,450 |
|
|
$ |
1,358 |
|
|
$ |
5,188 |
|
|
$ |
689 |
|
|
$ |
9,685 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,707 |
) |
|
|
|
|
|
|
(1,707 |
) |
Dividends on Common Shares |
|
|
(Note 13) |
|
|
|
|
|
|
|
|
|
|
|
(52 |
) |
|
|
|
|
|
|
(52 |
) |
Common Shares Issued |
|
|
(Note 13) |
|
|
|
1,098 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,098 |
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
(Note 13) |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
Other Comprehensive Income |
|
|
(Note 14) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
479 |
|
|
|
479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2015 |
|
|
|
|
|
$ |
3,562 |
|
|
$ |
1,358 |
|
|
$ |
3,429 |
|
|
$ |
1,168 |
|
|
$ |
9,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2014 ($ millions) |
|
|
|
|
Share Capital |
|
|
Paid in Surplus |
|
|
Retained Earnings |
|
|
Accumulated Other Comprehensive Income |
|
|
Total Shareholders Equity |
|
|
|
|
|
|
|
|
Balance, December 31, 2013 |
|
|
|
|
|
$ |
2,445 |
|
|
$ |
15 |
|
|
$ |
2,003 |
|
|
$ |
684 |
|
|
$ |
5,147 |
|
Share-Based Compensation |
|
|
(Note 17) |
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Net Earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
116 |
|
|
|
|
|
|
|
116 |
|
Dividends on Common Shares |
|
|
(Note 13) |
|
|
|
|
|
|
|
|
|
|
|
(52 |
) |
|
|
|
|
|
|
(52 |
) |
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
(Note 13) |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Other Comprehensive Income |
|
|
(Note 14) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2014 |
|
|
|
|
|
$ |
2,446 |
|
|
$ |
13 |
|
|
$ |
2,067 |
|
|
$ |
708 |
|
|
$ |
5,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Condensed Consolidated Statement of Cash Flows (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
($ millions) |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
|
|
|
|
$ |
(1,707 |
) |
|
$ |
116 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
466 |
|
|
|
418 |
|
Impairments |
|
|
(Note 9) |
|
|
|
1,916 |
|
|
|
|
|
Accretion of asset retirement obligation |
|
|
(Note 12) |
|
|
|
12 |
|
|
|
13 |
|
Deferred income taxes |
|
|
(Note 8) |
|
|
|
(963 |
) |
|
|
12 |
|
Unrealized (gain) loss on risk management |
|
|
(Note 20) |
|
|
|
136 |
|
|
|
285 |
|
Unrealized foreign exchange (gain) loss |
|
|
(Note 7) |
|
|
|
559 |
|
|
|
197 |
|
(Gain) loss on divestitures |
|
|
(Note 5) |
|
|
|
(14 |
) |
|
|
1 |
|
Other |
|
|
|
|
|
|
90 |
|
|
|
52 |
|
Net change in other assets and liabilities |
|
|
|
|
|
|
(7 |
) |
|
|
(9 |
) |
Net change in non-cash working capital |
|
|
|
|
|
|
(6 |
) |
|
|
(142 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
|
|
|
|
|
482 |
|
|
|
943 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(Note 3) |
|
|
|
(736 |
) |
|
|
(511 |
) |
Acquisitions |
|
|
(Note 5) |
|
|
|
(35 |
) |
|
|
(23 |
) |
Proceeds from divestitures |
|
|
(Note 5) |
|
|
|
873 |
|
|
|
47 |
|
Cash in reserve |
|
|
|
|
|
|
29 |
|
|
|
3 |
|
Net change in investments and other |
|
|
|
|
|
|
137 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Investing Activities |
|
|
|
|
|
|
268 |
|
|
|
(446 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net issuance (repayment) of revolving long-term debt |
|
|
|
|
|
|
(66 |
) |
|
|
|
|
Repayment of long-term debt |
|
|
(Note 10) |
|
|
|
|
|
|
|
(770 |
) |
Issuance of common shares |
|
|
(Note 13) |
|
|
|
1,088 |
|
|
|
|
|
Dividends on common shares |
|
|
(Note 13) |
|
|
|
(38 |
) |
|
|
(51 |
) |
Capital lease payments and other financing arrangements |
|
|
(Note 11) |
|
|
|
(16 |
) |
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Financing Activities |
|
|
|
|
|
|
968 |
|
|
|
(845 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
|
|
|
|
|
(26 |
) |
|
|
(56 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
|
|
|
1,692 |
|
|
|
(404 |
) |
Cash and Cash Equivalents, Beginning of Period |
|
|
|
|
|
|
338 |
|
|
|
2,566 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
$ |
2,030 |
|
|
$ |
2,162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, End of Period |
|
|
|
|
|
$ |
202 |
|
|
$ |
208 |
|
Cash Equivalents, End of Period |
|
|
|
|
|
|
1,828 |
|
|
|
1,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
$ |
2,030 |
|
|
$ |
2,162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
1. |
Basis of Presentation and Principles of Consolidation |
Encana Corporation and its subsidiaries
(Encana or the Company) are in the business of the exploration for, the development of, and the production and marketing of natural gas, oil and natural gas liquids (NGLs). The term liquids is used to represent
Encanas oil, NGLs and condensate.
The interim Condensed Consolidated Financial Statements include the accounts of Encana and are presented in
accordance with accounting principles generally accepted in the United States (U.S. GAAP).
The interim Condensed Consolidated Financial
Statements include the accounts of Encana and entities in which it holds a controlling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in natural gas and oil exploration and production joint
ventures and partnerships are consolidated on a proportionate basis. Investments in non-controlled entities over which Encana has the ability to exercise significant influence are accounted for using the equity method.
The interim Condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual
audited Consolidated Financial Statements for the year ended December 31, 2014, except as noted below in Note 2. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. Certain
information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Condensed Consolidated
Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2014.
These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to
present fairly the financial position and results of the Company as at and for the periods presented. Interim condensed consolidated financial results are not necessarily indicative of consolidated financial results expected for the fiscal year.
2. |
Recent Accounting Pronouncements |
Changes in Accounting Policies and Practices
On January 1, 2015, Encana adopted Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of
Disposals of Components of an Entity as issued by the Financial Accounting Standards Board (FASB). The update amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only
disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments have been applied prospectively and have not had a material impact on the Companys interim Condensed Consolidated Financial
Statements.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
2. |
Recent Accounting Pronouncements (continued) |
New Standards Issued Not Yet Adopted
As of January 1, 2016, Encana will be required to adopt the following pronouncements issued by the FASB:
|
|
|
ASU 2014-12, Compensation - Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period. The
update requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied prospectively and are not expected to have a material
impact on the Companys Consolidated Financial Statements. |
|
|
|
ASU 2015-02, Amendments to the Consolidation Analysis. The update requires limited partnerships and similar entities to be evaluated under the variable interest and voting interest models, eliminate the
presumption that a general partner should consolidate a limited partnership, and simplify the identification of variable interests and related effect on the primary beneficiary criterion when fees are paid to a decision maker. The amendments can be
applied using either a full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the amendments on the Companys Consolidated Financial Statements.
|
|
|
|
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs to be presented on the balance sheet as a deduction from the carrying amount of the related
liability. Previously, debt issuance costs were presented as a deferred charge within assets. The amendments will be applied retrospectively. As at March 31, 2015, $43 million of debt issuance costs were presented in Other Assets on the
Companys interim Condensed Consolidated Balance Sheet ($48 million as at December 31, 2014). |
As of January 1, 2017,
Encana will be required to adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605,
Revenue Recognition, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an
amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of
adoption. Encana is currently assessing the potential impact of the standard on the Companys Consolidated Financial Statements.
Encanas reportable segments are determined based on the Companys
operations and geographic locations as follows:
|
|
|
Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the Canadian cost centre. |
|
|
|
USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S. cost centre. |
|
|
|
Market Optimization is primarily responsible for the sale of the Companys proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third
party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market
Optimization sells substantially all of the Companys upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation. |
Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized
gains and losses are recorded in the reporting segment to which the derivative instruments relate.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
3. |
Segmented Information (continued) |
Results of Operations (For the three months ended March 31)
Segment and Geographic Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
USA Operations |
|
|
Market Optimization |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
Revenues, Net of Royalties |
|
$ |
632 |
|
|
$ |
1,193 |
|
|
$ |
588 |
|
|
$ |
713 |
|
|
$ |
139 |
|
|
$ |
244 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
5 |
|
|
|
19 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
177 |
|
|
|
215 |
|
|
|
155 |
|
|
|
163 |
|
|
|
|
|
|
|
|
|
Operating |
|
|
42 |
|
|
|
92 |
|
|
|
125 |
|
|
|
74 |
|
|
|
16 |
|
|
|
13 |
|
Purchased product |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121 |
|
|
|
228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
413 |
|
|
|
881 |
|
|
|
289 |
|
|
|
434 |
|
|
|
2 |
|
|
|
3 |
|
Depreciation, depletion and amortization |
|
|
105 |
|
|
|
172 |
|
|
|
336 |
|
|
|
212 |
|
|
|
|
|
|
|
3 |
|
Impairments |
|
|
|
|
|
|
|
|
|
|
1,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
308 |
|
|
$ |
709 |
|
|
$ |
(1,963 |
) |
|
$ |
222 |
|
|
$ |
2 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
Consolidated |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
Revenues, Net of Royalties |
|
$ |
(110 |
) |
|
$ |
(258 |
) |
|
$ |
1,249 |
|
|
$ |
1,892 |
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
47 |
|
Transportation and processing |
|
|
8 |
|
|
|
1 |
|
|
|
340 |
|
|
|
379 |
|
Operating |
|
|
6 |
|
|
|
10 |
|
|
|
189 |
|
|
|
189 |
|
Purchased product |
|
|
|
|
|
|
|
|
|
|
121 |
|
|
|
228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(124 |
) |
|
|
(269 |
) |
|
|
580 |
|
|
|
1,049 |
|
Depreciation, depletion and amortization |
|
|
25 |
|
|
|
31 |
|
|
|
466 |
|
|
|
418 |
|
Impairments |
|
|
|
|
|
|
|
|
|
|
1,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(149 |
) |
|
$ |
(300 |
) |
|
|
(1,802 |
) |
|
|
631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
13 |
|
Administrative |
|
|
|
|
|
|
|
|
|
|
72 |
|
|
|
102 |
|
Interest |
|
|
|
|
|
|
|
|
|
|
125 |
|
|
|
147 |
|
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
656 |
|
|
|
224 |
|
(Gain) loss on divestitures |
|
|
|
|
|
|
|
|
|
|
(14 |
) |
|
|
1 |
|
Other |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
852 |
|
|
|
487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
(2,654 |
) |
|
|
144 |
|
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
(947 |
) |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
$ |
(1,707 |
) |
|
$ |
116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
|
Marketing Sales |
|
|
Upstream Eliminations |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
Revenues, Net of Royalties |
|
$ |
1,165 |
|
|
$ |
2,227 |
|
|
$ |
(1,026 |
) |
|
$ |
(1,983 |
) |
|
$ |
139 |
|
|
$ |
244 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
95 |
|
|
|
127 |
|
|
|
(95 |
) |
|
|
(127 |
) |
|
|
|
|
|
|
|
|
Operating |
|
|
16 |
|
|
|
25 |
|
|
|
|
|
|
|
(12 |
) |
|
|
16 |
|
|
|
13 |
|
Purchased product |
|
|
1,052 |
|
|
|
2,070 |
|
|
|
(931 |
) |
|
|
(1,842 |
) |
|
|
121 |
|
|
|
228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
$ |
2 |
|
|
$ |
5 |
|
|
$ |
|
|
|
$ |
(2 |
) |
|
$ |
2 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
3. |
Segmented Information (continued) |
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2015 |
|
|
2014 |
|
|
|
|
Canadian Operations |
|
$ |
151 |
|
|
$ |
281 |
|
USA Operations |
|
|
583 |
|
|
|
226 |
|
Market Optimization |
|
|
|
|
|
|
1 |
|
Corporate & Other |
|
|
2 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
736 |
|
|
$ |
511 |
|
|
|
|
|
|
|
|
|
|
Goodwill, Property, Plant and Equipment and Total Assets by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
Property, Plant and Equipment |
|
|
Total Assets |
|
|
As at |
|
|
As at |
|
|
As at |
|
|
March 31, 2015 |
|
|
December 31, 2014 |
|
|
March 31, 2015 |
|
|
December 31, 2014 |
|
|
March 31, 2015 |
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
721 |
|
|
$ |
788 |
|
|
$ |
1,304 |
|
|
$ |
2,338 |
|
|
$ |
2,447 |
|
|
$ |
3,632 |
|
USA Operations |
|
|
2,129 |
|
|
|
2,129 |
|
|
|
12,166 |
|
|
|
13,817 |
|
|
|
14,779 |
|
|
|
16,800 |
|
Market Optimization |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
73 |
|
|
|
181 |
|
Corporate & Other |
|
|
|
|
|
|
|
|
|
|
1,691 |
|
|
|
1,859 |
|
|
|
5,537 |
|
|
|
4,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,850 |
|
|
$ |
2,917 |
|
|
$ |
15,162 |
|
|
$ |
18,015 |
|
|
$ |
22,836 |
|
|
$ |
24,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford Acquisition
On June 20, 2014, Encana completed the acquisition of properties located in the Eagle Ford shale formation for approximately $2.9 billion, after closing
adjustments. The acquisition included an interest in certain producing properties and undeveloped lands in the Karnes, Wilson and Atascosa counties of south Texas. Encana funded the acquisition with cash on hand. Transaction costs of approximately
$9 million were included in other expenses.
Athlon Energy Inc. Acquisition
On November 13, 2014, Encana completed the acquisition of all of the issued and outstanding shares of common stock of Athlon Energy Inc.
(Athlon) for $5.93 billion, or $58.50 per share. In addition, Encana assumed Athlons $1.15 billion senior notes and repaid and terminated Athlons credit facility with indebtedness outstanding of $335 million. Encana funded
the acquisition of Athlon with cash on hand. Transaction costs of approximately $31 million were included in other expenses. Following completion of the acquisition, Athlons $1.15 billion senior notes were redeemed in accordance with the
provisions of the governing indentures. Athlons operations focused on the acquisition and development of oil and gas properties located in the Permian Basin in Texas.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
4. |
Business Combinations (continued) |
Purchase Price Allocations
The transactions were accounted for under the acquisition method, which requires that the assets acquired and liabilities assumed be recognized at their fair
values as of the acquisition date. The purchase price allocations, representing consideration paid and the fair values of the assets acquired and liabilities assumed as of the acquisition date, are shown in the table below.
|
|
|
|
|
|
|
|
|
Purchase Price Allocation |
|
Eagle Ford (1) |
|
|
Athlon (2, 3) |
|
|
|
|
Assets Acquired: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
|
|
|
$ |
2 |
|
Accounts receivable and other current assets |
|
|
4 |
|
|
|
133 |
|
Risk management |
|
|
|
|
|
|
80 |
|
Proved properties |
|
|
2,873 |
|
|
|
2,124 |
|
Unproved properties |
|
|
78 |
|
|
|
5,338 |
|
Other property, plant and equipment |
|
|
|
|
|
|
2 |
|
Other assets |
|
|
|
|
|
|
2 |
|
Goodwill |
|
|
|
|
|
|
1,724 |
|
Liabilities Assumed: |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
|
(195 |
) |
Long-term debt, including revolving credit facility |
|
|
|
|
|
|
(1,497 |
) |
Asset retirement obligation |
|
|
(32 |
) |
|
|
(25 |
) |
Deferred income taxes |
|
|
|
|
|
|
(1,724 |
) |
|
|
|
|
|
|
|
|
|
Total Purchase Price |
|
$ |
2,923 |
|
|
$ |
5,964 |
|
|
|
|
|
|
|
|
|
|
(1) |
The purchase price allocation for Eagle Ford is finalized. |
(2) |
The purchase price allocation for Athlon is preliminary. There were no changes during the first quarter of 2015. |
(3) |
The purchase price includes cash consideration paid for issued and outstanding shares of common stock of Athlon of $58.50 per share totaling $5.93 billion, as well as payments to terminate certain employment agreements
with Athlons management and payments for certain other existing obligations of Athlon. |
The Company used the income approach valuation
technique for the fair value of assets acquired and liabilities assumed. The carrying amounts of cash, accounts receivable and other current assets, and accounts payable and accrued liabilities approximate their fair values due to the short-term
maturity of the instruments. The fair values of the risk management assets and long-term debt, including the revolving credit facility, are categorized within Level 2 of the fair value hierarchy and were determined using quoted prices and rates from
an available pricing source. The fair values of the proved and unproved properties, other property, plant and equipment, other assets, goodwill, and asset retirement obligation are categorized within Level 3 and were determined using relevant market
assumptions, including discount rates, future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates to abandon and reclaim producing wells.
Goodwill arose from the Athlon acquisition primarily from the requirement to recognize deferred taxes on the difference between the fair value of the assets
acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not amortized and is not deductible for tax purposes.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
4. |
Business Combinations (continued) |
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information combines the historical financial results of Encana with Eagle Ford and Athlon, and has been prepared
assuming the acquisitions occurred on January 1, 2014. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combinations had been completed at the date indicated. In
addition, the pro forma information does not project Encanas results of operations for any future period. The Companys consolidated results for the three months ended March 31, 2015 include the results from Eagle Ford and Athlon.
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2014 ($ millions, except per share amounts) |
|
Eagle Ford |
|
|
Athlon |
|
|
|
|
Revenues, Net of Royalties |
|
$ |
2,276 |
|
|
$ |
1,987 |
|
Net Earnings |
|
$ |
268 |
|
|
$ |
118 |
|
Net Earnings per Common Share Basic & Diluted |
|
$ |
0.36 |
|
|
$ |
0.16 |
|
5. |
Acquisitions and Divestitures |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2015 |
|
|
2014 |
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
|
|
|
$ |
2 |
|
USA Operations |
|
|
1 |
|
|
|
21 |
|
Corporate & Other |
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Acquisitions |
|
|
35 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Divestitures |
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
(829 |
) |
|
|
(32 |
) |
USA Operations |
|
|
3 |
|
|
|
(14 |
) |
Corporate & Other |
|
|
(47 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
Total Divestitures |
|
|
(873 |
) |
|
|
(47 |
) |
|
|
|
|
|
|
|
|
|
Net Acquisitions & (Divestitures) |
|
$ |
(838 |
) |
|
$
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
Divestitures
For the
three months ended March 31, 2015, divestitures in the Canadian Operations were $829 million (2014 - $32 million), which primarily included the sale of certain assets in Wheatland located in central and southern Alberta for proceeds of
approximately C$558 million ($468 million), after closing adjustments and the sale of certain natural gas gathering and compression assets in the Montney area of northeastern British Columbia for proceeds of approximately C$455 million ($359
million) after closing adjustments. Amounts received from the divestiture transactions have been deducted from the Canadian full cost pool.
Corporate and
Other acquisitions and divestitures include the purchase and subsequent sale of the Encana Place office building located in Calgary, which resulted in a gain on divestiture of approximately $12 million.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2015 |
|
|
2014 |
|
|
|
|
Interest Expense on: |
|
|
|
|
|
|
|
|
Debt |
|
$ |
95 |
|
|
$ |
112 |
|
The Bow office building |
|
|
16 |
|
|
|
19 |
|
Capital leases |
|
|
9 |
|
|
|
9 |
|
Other |
|
|
5 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
125 |
|
|
$ |
147 |
|
|
|
|
|
|
|
|
|
|
7. |
Foreign Exchange (Gain) Loss, Net |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2015 |
|
|
2014 |
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|
Translation of U.S. dollar debt issued from Canada |
|
$ |
464 |
|
|
$ |
204 |
|
Translation of U.S. dollar risk management contracts issued from Canada |
|
|
(35 |
) |
|
|
(7 |
) |
Translation of intercompany notes |
|
|
130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
559 |
|
|
|
197 |
|
Foreign Exchange on Intercompany Transactions |
|
|
(2 |
) |
|
|
26 |
|
Other Monetary Revaluations and Settlements |
|
|
99 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
656 |
|
|
$ |
224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2015 |
|
|
2014 |
|
|
|
|
Current Tax |
|
|
|
|
|
|
|
|
Canada |
|
$ |
13 |
|
|
$ |
7 |
|
United States |
|
|
1 |
|
|
|
3 |
|
Other countries |
|
|
2 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
Total Current Tax Expense |
|
|
16 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax |
|
|
|
|
|
|
|
|
Canada |
|
|
(323 |
) |
|
|
4 |
|
United States |
|
|
(760 |
) |
|
|
2 |
|
Other countries |
|
|
120 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Expense (Recovery) |
|
|
(963 |
) |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(947 |
) |
|
$ |
28 |
|
|
|
|
|
|
|
|
|
|
Encanas interim income tax expense is determined using an estimated annual effective income tax rate applied to
year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by the expected annual earnings, statutory rate and other foreign
differences, non-taxable capital gains and losses, tax differences on divestitures and transactions and partnership tax allocations in excess of funding.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
9. |
Property, Plant and Equipment, Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
|
Accumulated |
|
|
Accumulated |
|
|
|
Cost |
|
|
DD&A (1) |
|
|
Net |
|
|
Cost |
|
|
DD&A (1) |
|
|
Net |
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
16,016 |
|
|
$ |
(15,257 |
) |
|
$ |
759 |
|
|
$ |
18,271 |
|
|
$ |
(16,566 |
) |
|
$ |
1,705 |
|
Unproved properties |
|
|
420 |
|
|
|
|
|
|
|
420 |
|
|
|
478 |
|
|
|
|
|
|
|
478 |
|
Other |
|
|
125 |
|
|
|
|
|
|
|
125 |
|
|
|
155 |
|
|
|
|
|
|
|
155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,561 |
|
|
|
(15,257 |
) |
|
|
1,304 |
|
|
|
18,904 |
|
|
|
(16,566 |
) |
|
|
2,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
25,009 |
|
|
|
(18,508 |
) |
|
|
6,501 |
|
|
|
24,279 |
|
|
|
(16,260 |
) |
|
|
8,019 |
|
Unproved properties |
|
|
5,564 |
|
|
|
|
|
|
|
5,564 |
|
|
|
5,655 |
|
|
|
|
|
|
|
5,655 |
|
Other |
|
|
101 |
|
|
|
|
|
|
|
101 |
|
|
|
143 |
|
|
|
|
|
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,674 |
|
|
|
(18,508 |
) |
|
|
12,166 |
|
|
|
30,077 |
|
|
|
(16,260 |
) |
|
|
13,817 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
7 |
|
|
|
(6 |
) |
|
|
1 |
|
|
|
8 |
|
|
|
(7 |
) |
|
|
1 |
|
Corporate & Other |
|
|
2,274 |
|
|
|
(583 |
) |
|
|
1,691 |
|
|
|
2,470 |
|
|
|
(611 |
) |
|
|
1,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
49,516 |
|
|
$ |
(34,354 |
) |
|
$ |
15,162 |
|
|
$ |
51,459 |
|
|
$ |
(33,444 |
) |
|
$ |
18,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Depreciation, depletion and amortization. |
Canadian Operations and USA Operations property, plant and
equipment include internal costs directly related to exploration, development and construction activities of $56 million which have been capitalized during the three months ended March 31, 2015 (2014 - $101 million). Included in Corporate and
Other are $61 million ($65 million as at December 31, 2014) of international property costs, which have been fully impaired.
For the three months
ended March 31, 2015, the Company recognized a ceiling test impairment of $1,916 million (2014 - nil) before tax in the U.S. cost centre, which is included within accumulated DD&A in the table above. The impairment resulted primarily from
the decline in the 12-month average trailing commodity prices which reduced proved reserves volumes and values. There was no ceiling test impairment in the Canadian cost centre for the three months ended March 31, 2015 (2014 - nil).
The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for
basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
|
Henry Hub ($/MMBtu) |
|
|
AECO (C$/MMBtu) |
|
|
WTI ($/bbl) |
|
|
Edmonton Light Sweet (C$/bbl) |
|
12-Month Average Trailing Reserves Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015 |
|
|
3.88 |
|
|
|
3.86 |
|
|
|
82.72 |
|
|
|
84.80 |
|
December 31, 2014 |
|
|
4.34 |
|
|
|
4.63 |
|
|
|
94.99 |
|
|
|
96.40 |
|
March 31, 2014 |
|
|
3.99 |
|
|
|
3.83 |
|
|
|
98.46 |
|
|
|
96.84 |
|
Capital Lease Arrangements
The Company has several lease arrangements that are accounted for as capital leases, including an office building, equipment and an offshore production
platform.
In December 2013, Encana commenced commercial operations at its Deep Panuke facility located offshore Nova Scotia at which time the Company
recorded a capital lease asset and a corresponding capital lease obligation related to the Production Field Centre (PFC). Variable interests related to the PFC are described in Note 15.
As at March 31, 2015, the total carrying value of assets under capital lease was $464 million ($547 million as at December 31, 2014). Liabilities
for the capital lease arrangements are included in other liabilities and provisions in the Condensed Consolidated Balance Sheet and are disclosed in Note 11.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
9. |
Property, Plant and Equipment, Net (continued) |
Other Arrangement
As at March 31, 2015, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,303 million ($1,431 million as at
December 31, 2014) related to The Bow office building, which is under a 25-year lease agreement. The Bow asset is being depreciated over the 60-year estimated life of the building. At the conclusion of the 25-year term, the remaining asset and
corresponding liability are expected to be derecognized as disclosed in Note 11.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C$ Principal Amount |
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
|
Canadian Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
|
|
5.80% due January 18, 2018 |
|
$ |
750 |
|
|
$ |
591 |
|
|
$ |
647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit and term loan borrowings |
|
|
|
|
|
|
1,211 |
|
|
|
1,277 |
|
U.S. Unsecured Notes |
|
|
|
|
|
|
|
|
|
|
|
|
5.90% due December 1, 2017 |
|
|
|
|
|
|
700 |
|
|
|
700 |
|
6.50% due May 15, 2019 |
|
|
|
|
|
|
500 |
|
|
|
500 |
|
3.90% due November 15, 2021 |
|
|
|
|
|
|
600 |
|
|
|
600 |
|
8.125% due September 15, 2030 |
|
|
|
|
|
|
300 |
|
|
|
300 |
|
7.20% due November 1, 2031 |
|
|
|
|
|
|
350 |
|
|
|
350 |
|
7.375% due November 1, 2031 |
|
|
|
|
|
|
500 |
|
|
|
500 |
|
6.50% due August 15, 2034 |
|
|
|
|
|
|
750 |
|
|
|
750 |
|
6.625% due August 15, 2037 |
|
|
|
|
|
|
500 |
|
|
|
500 |
|
6.50% due February 1, 2038 |
|
|
|
|
|
|
800 |
|
|
|
800 |
|
5.15% due November 15, 2041 |
|
|
|
|
|
|
400 |
|
|
|
400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,611 |
|
|
|
6,677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Principal |
|
|
|
|
|
|
7,202 |
|
|
|
7,324 |
|
|
|
|
|
Increase in Value of Debt Acquired |
|
|
|
|
|
|
30 |
|
|
|
34 |
|
Debt Discounts |
|
|
|
|
|
|
(16 |
) |
|
|
(18 |
) |
Current Portion of Long-Term Debt |
|
|
|
|
|
|
(1,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5,925 |
|
|
$ |
7,340 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt is accounted for at amortized cost using the effective interest method of amortization. As at March 31,
2015, total long-term debt had a carrying value of $7,216 million and a fair value of $8,048 million (as at December 31, 2014 - carrying value of $7,340 million and a fair value of $7,788 million). The estimated fair value of long-term
borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period
end.
On March 5, 2015, Encana provided notice to note holders that it would redeem the Companys $700 million 5.90 percent notes due
December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018. Accordingly, these notes are presented within the current portion of long-term debt on the Companys Condensed Consolidated Balance Sheet as at
March 31, 2015. On April 6, 2015, the Company used net proceeds from the common shares issued, as disclosed in Note 13, and cash on hand to complete the note redemptions.
On February 28, 2014, Encana announced a cash tender offer and consent solicitation for any and all of the Companys outstanding $1,000 million 5.80
percent notes with a maturity date of May 1, 2014. The Company paid $1,004.59 for each $1,000 principal amount of the notes plus accrued and unpaid interest up to, but not including, the settlement date and a consent payment equal to $2.50 per
$1,000 principal amount of the notes.
On March 28, 2014, the tender offer and consent solicitation expired and on March 31, 2014, Encana paid
the consenting note holders an aggregate of approximately $792 million in cash reflecting a $768 million principal debt repayment, $2 million for the consent payment and $22 million of accrued and unpaid interest.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
11. |
Other Liabilities and Provisions |
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
The Bow Office Building (See Note 9) |
|
$ |
1,358 |
|
|
$ |
1,486 |
|
Capital Lease Obligations (See Note 9) |
|
|
424 |
|
|
|
473 |
|
Unrecognized Tax Benefits |
|
|
238 |
|
|
|
279 |
|
Pensions and Other Post-Employment Benefits |
|
|
147 |
|
|
|
144 |
|
Long-Term Incentives (See Note 17) |
|
|
21 |
|
|
|
70 |
|
Other |
|
|
37 |
|
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,225 |
|
|
$ |
2,484 |
|
|
|
|
|
|
|
|
|
|
The Bow Office Building
As described in Note 9, Encana has recognized the accumulated costs for The Bow office building, which is under a 25-year lease agreement. At the conclusion of
the 25-year term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased part of The Bow office space to a subsidiary of Cenovus Energy Inc. (Cenovus). The total undiscounted future
payments related to the lease agreement and the total undiscounted future amounts expected to be recovered from the Cenovus sublease are outlined below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
Expected Future Lease Payments |
|
$ |
55 |
|
|
$ |
74 |
|
|
$ |
75 |
|
|
$ |
75 |
|
|
$ |
76 |
|
|
$ |
1,511 |
|
|
$ |
1,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sublease Recoveries |
|
$ |
(27 |
) |
|
$ |
(36 |
) |
|
$ |
(37 |
) |
|
$ |
(37 |
) |
|
$ |
(37 |
) |
|
$ |
(743 |
) |
|
$ |
(917 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Lease Obligations
As described in Note 9, the Company has several lease arrangements that are accounted for as capital leases, including an office building, equipment and an
offshore production platform. Variable interests related to the PFC are described in Note 15.
The total expected future lease payments related to the
Companys capital lease obligations are outlined below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Expected Future Lease Payments |
|
$ |
74 |
|
|
$ |
98 |
|
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
232 |
|
|
$ |
701 |
|
Less Amounts Representing Interest |
|
|
31 |
|
|
|
41 |
|
|
|
37 |
|
|
|
33 |
|
|
|
29 |
|
|
|
50 |
|
|
|
221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Value of Expected Future Lease Payments |
|
$ |
43 |
|
|
$ |
57 |
|
|
$ |
62 |
|
|
$ |
66 |
|
|
$ |
70 |
|
|
$ |
182 |
|
|
$ |
480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
12. |
Asset Retirement Obligation |
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
Asset Retirement Obligation, Beginning of Year |
|
$ |
913 |
|
|
$ |
966 |
|
Liabilities Incurred and Acquired (See Note 4) |
|
|
9 |
|
|
|
85 |
|
Liabilities Settled and Divested |
|
|
(86 |
) |
|
|
(188 |
) |
Change in Estimated Future Cash Outflows |
|
|
|
|
|
|
35 |
|
Accretion Expense |
|
|
12 |
|
|
|
52 |
|
Foreign Currency Translation |
|
|
(34 |
) |
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation, End of Period |
|
$ |
814 |
|
|
$ |
913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Portion |
|
$ |
41 |
|
|
$ |
43 |
|
Long-Term Portion |
|
|
773 |
|
|
|
870 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
814 |
|
|
$ |
913 |
|
|
|
|
|
|
|
|
|
|
Authorized
The Company is authorized to issue an unlimited number of no par value common shares, an unlimited number of first preferred shares and an unlimited number of
second preferred shares.
Issued and Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
Number (millions) |
|
|
Amount |
|
|
Number (millions) |
|
|
Amount |
|
|
|
|
|
|
Common Shares Outstanding, Beginning of Year |
|
|
741.2 |
|
|
$ |
2,450 |
|
|
|
740.9 |
|
|
$ |
2,445 |
|
Common Shares Issued |
|
|
98.4 |
|
|
|
1,098 |
|
|
|
|
|
|
|
|
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
1.3 |
|
|
|
14 |
|
|
|
0.3 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shares Outstanding, End of Period |
|
|
840.9 |
|
|
$ |
3,562 |
|
|
|
741.2 |
|
|
$ |
2,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On March 5, 2015, Encana filed a prospectus supplement (the Share Offering) to the Companys base shelf
prospectus for the issuance of 85,616,500 common shares and granted an over-allotment option for up to an additional 12,842,475 common shares at a price of C$14.60 per common share, pursuant to an underwriting agreement. The aggregate gross proceeds
from the Share Offering were approximately C$1.44 billion ($1.13 billion). After deducting underwriters fees and costs of the Share Offering, the net proceeds received were approximately C$1.39 billion ($1.09 billion).
During the three months ended March 31, 2015, Encana issued 1,267,680 common shares totaling $14 million under the Companys dividend reinvestment
plan (DRIP). During the twelve months ended December 31, 2014, Encana issued 240,839 common shares totaling $5 million under the DRIP.
Dividends
During the three months ended March 31,
2015, Encana paid dividends of $0.07 per common share totaling $52 million (2014 - $0.07 per common share totaling $52 million). Common shares issued as part of the Share Offering as described above were not eligible to receive the dividend paid on
March 31, 2015.
For the three months ended March 31, 2015, the dividends paid included $14 million in common shares which were issued in lieu
of cash dividends under the DRIP (2014 - $1 million).
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
13. |
Share Capital (continued) |
Earnings Per Common Share
The following table presents the computation of net earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(millions, except per share amounts) |
|
2015 |
|
|
2014 |
|
|
|
|
Net Earnings (Loss) |
|
$ |
(1,707 |
) |
|
$ |
116 |
|
|
|
|
Number of Common Shares: |
|
|
|
|
|
|
|
|
Weighted average common shares outstanding - Basic |
|
|
757.8 |
|
|
|
741.0 |
|
Effect of dilutive securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding - Diluted |
|
|
757.8 |
|
|
|
741.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(2.25 |
) |
|
$ |
0.16 |
|
Diluted |
|
$ |
(2.25 |
) |
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
Encana Stock Option Plan
Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market
value of the common shares on the date the options are granted. All options outstanding as at March 31, 2015 have associated Tandem Stock Appreciation Rights (TSARs) attached. In lieu of exercising the option, the associated TSARs
give the option holder the right to receive a cash payment equal to the excess of the market price of Encanas common shares at the time of the exercise over the original grant price.
In addition, certain stock options granted are performance-based whereby vesting is also subject to Encana attaining prescribed performance relative to
predetermined key measures. Historically, most holders of options with TSARs have elected to exercise their stock options as a Stock Appreciation Right (SAR) in exchange for a cash payment. As a result, Encana does not consider
outstanding TSARs to be potentially dilutive securities.
Encana Restricted Share Units (RSUs)
Encana has a share-based compensation plan whereby eligible employees are granted RSUs. An RSU is a conditional grant to receive an Encana common share, or the
cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company intends to settle vested RSUs in cash on the vesting date. As a result, Encana does not consider
RSUs to be potentially dilutive securities.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
14. |
Accumulated Other Comprehensive Income |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
$ |
715 |
|
|
$ |
693 |
|
Current Period Change in Foreign Currency Translation Adjustment |
|
|
478 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
Balance, End of Period |
|
$ |
1,193 |
|
|
$ |
717 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and Other Post-Employment Benefit Plans |
|
|
|
|
|
|
|
|
Balance, Beginning of Year |
|
$ |
(26 |
) |
|
$ |
(9 |
) |
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 18) |
|
|
1 |
|
|
|
|
|
Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, End of Period |
|
$ |
(25 |
) |
|
$ |
(9 |
) |
|
|
|
|
|
|
|
|
|
Total Accumulated Other Comprehensive Income |
|
$ |
1,168 |
|
|
$ |
708 |
|
|
|
|
|
|
|
|
|
|
15. |
Variable Interest Entities |
Production Field Centre
In 2008, Encana entered into a contract for the design, construction and operation of the PFC at its Deep Panuke facility. Upon commencement of operations in
December 2013, Encana recognized the PFC as a capital lease asset as described in Note 9. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12 one-year terms at fixed prices after the initial lease term
expires in 2021.
As a result of the purchase option and fixed price renewal options, Encana has determined it holds variable interests and that the
related leasing entity qualifies as a variable interest entity (VIE). Encana is not the primary beneficiary of the VIE as the Company does not have the power to direct the activities that most significantly impact the VIEs economic
performance. Encana is not required to provide any financial support or guarantees to the leasing entity or its affiliates, other than the contractual payments under the lease and operating agreements. Encanas maximum exposure to loss is the
expected lease payments over the initial contract term. As at March 31, 2015, Encanas capital lease obligation of $410 million ($462 million as at December 31, 2014) related to the PFC.
Veresen Midstream Limited Partnership
On March 31,
2015, Encana, along with the Cutbank Ridge Partnership (CRP), entered into natural gas gathering and compression agreements with Veresen Midstream Limited Partnership (VMLP), under an initial term of 30 years with two
potential five-year renewal terms. As part of the agreement, VMLP agreed to undertake expansion of future midstream services in support of Encana and the CRPs development of the Montney play. In addition, VMLP will also provide to Encana and
the CRP natural gas gathering and processing under existing agreements that were contributed to VMLP by its partner Veresen Inc., with remaining terms of 17 years and up to a potential maximum of 10 one-year renewal terms.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
15. |
Variable Interest Entities (continued) |
Encana has determined that VMLP is a VIE and that Encana holds variable interests in VMLP. Encana is not the
primary beneficiary as the Company does not have the power to direct the activities that most significantly impact VMLPs economic performance. These key activities relate to the construction, operation, maintenance and marketing of assets
owned by VMLP. The variable interests arise from certain terms under the long-term service agreements which include: i) a take or pay for volumes committed to certain gathering and processing assets ii) an operating fee of which a portion can be
converted into a take or pay once VMLP assumes operatorship of certain compression assets and iii) a potential payout of minimum costs associated with certain gathering and compression assets. The potential payout of minimum costs is assessed in the
eighth year of the assets service period based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain agreements. The potential payout amount can be reduced in the event VMLP
procures unused capacity to third party users. Encana is not required to provide any financial support or guarantees to VMLP.
The total maximum exposure
to loss as a result of Encanas involvement with VMLP is estimated to be $1,183 million as at March 31, 2015 and is based on the future take or pay for volumes committed to certain gathering and processing assets and the potential payout
of minimum costs associated with certain gathering and compression assets. The total maximum exposure to loss associated with the potential payout requirements are highly uncertain as the payout amount is contingent on future production estimates,
pace of development and capacity contracted to third parties. As at March 31, 2015, accounts payable and accrued liabilities includes $5 million related to the take or pay commitment. The take or pay for volumes committed to certain gathering
and processing agreements are included in Note 21.
16. |
Restructuring Charges |
In November 2013, Encana announced its plans to align the organizational
structure in support of the Companys strategy. Since the announcement, the Company has incurred restructuring charges primarily related to severance costs totaling $124 million, of which $3 million remains accrued as at March 31, 2015.
Total restructuring charges are expected to be approximately $134 million before tax. For the three months ended March 31, 2015, no restructuring charges were incurred (2014 - $15 million). The remaining restructuring charges of approximately
$10 million are anticipated to be incurred during the remainder of 2015. Restructuring charges are included in administrative expense in the Companys Condensed Consolidated Statement of Earnings.
Encana has a number of compensation arrangements under which the Company awards
various types of long-term incentive grants to eligible employees. These primarily include TSARs, Performance TSARs, SARs, Performance SARs, Performance Share Units (PSUs), Deferred Share Units (DSUs) and RSUs. These
compensation arrangements are share-based.
Encana accounts for TSARs, Performance TSARs, SARs, Performance SARs, PSUs and RSUs held by Encana employees
as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.
As at March 31, 2015, the following weighted average assumptions were used to determine the fair value of the share units held by Encana employees:
|
|
|
|
|
|
|
|
|
|
|
Encana US$ Share Units |
|
|
Encana C$ Share Units |
|
|
|
|
Risk Free Interest Rate |
|
|
0.50 |
% |
|
|
0.50 |
% |
Dividend Yield |
|
|
2.51 |
% |
|
|
2.46 |
% |
Expected Volatility Rate |
|
|
31.97 |
% |
|
|
30.06 |
% |
Expected Term |
|
|
1.9 yrs |
|
|
|
1.9 yrs |
|
Market Share Price |
|
US$ |
11.15 |
|
|
C$ |
14.14 |
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
17. |
Compensation Plans (continued) |
The Company has recognized the following share-based compensation costs:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
Compensation Costs of Transactions Classified as Cash-Settled |
|
$ |
(6 |
) |
|
$ |
72 |
|
Compensation Costs of Transactions Classified as Equity-Settled (1) |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
Total Share-Based Compensation Costs |
|
|
(6 |
) |
|
|
70 |
|
Less: Total Share-Based Compensation Costs Capitalized |
|
|
3 |
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
Total Share-Based Compensation Expense |
|
$ |
(3 |
) |
|
$ |
44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized on the Condensed Consolidated Statement of Earnings in: |
|
|
|
|
|
|
|
|
Operating expense |
|
$ |
(2 |
) |
|
$ |
20 |
|
Administrative expense |
|
|
(1 |
) |
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(3 |
) |
|
$ |
44 |
|
|
|
|
|
|
|
|
|
|
(1) |
RSUs may be settled In cash or equity as determined by Encana. The Companys decision to cash settle RSUs was made subsequent to the original grant date. |
As at March 31, 2015, the liability for share-based payment transactions totaled $82 million ($99 million as at December 31, 2014), of which $61
million ($29 million as at December 31, 2014) is recognized in accounts payable and accrued liabilities in the Condensed Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
Liability for Cash-Settled Share-Based Payment Transactions: |
|
|
|
|
|
|
|
|
Unvested |
|
$ |
64 |
|
|
$ |
78 |
|
Vested |
|
|
18 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
82 |
|
|
$ |
99 |
|
|
|
|
|
|
|
|
|
|
The following units were granted primarily in conjunction with the Companys March annual long-term incentive award. The
TSARs and SARs were granted at the volume-weighted average trading price of Encanas common shares for the five days prior to the grant date.
|
|
|
|
|
Three Months Ended March 31, 2015 (thousands of units) |
|
|
|
TSARs |
|
|
1,934 |
|
SARs |
|
|
1,444 |
|
PSUs |
|
|
2,291 |
|
DSUs |
|
|
158 |
|
RSUs |
|
|
6,353 |
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
18. |
Pension and Other Post-Employment Benefits |
The Company has recognized total benefit plans expense which
includes pension benefits and other post-employment benefits (OPEB) for the three months ended March 31 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Defined Benefit Plan Expense |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
4 |
|
|
$ |
3 |
|
Defined Contribution Plan Expense |
|
|
8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Benefit Plans Expense |
|
$ |
9 |
|
|
$ |
8 |
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
12 |
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Of the total benefit plans expense, $9 million (2014 - $8 million) was included in operating expense and $3 million (2014 - $3
million) was included in administrative expense.
The defined periodic pension and OPEB expense for the three months ended March 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Current Service Costs |
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
3 |
|
|
$ |
3 |
|
Interest Cost |
|
|
2 |
|
|
|
3 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
4 |
|
Expected Return On Plan Assets |
|
|
(3 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
(4 |
) |
Amounts Reclassified From Accumulated Other Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial (gains) and losses |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Defined Benefit Plan Expense |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
4 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amounts recognized in other comprehensive income for the three months ended March 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Total Amounts Recognized in Other Comprehensive (Income) Loss, Before Tax |
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Amounts Recognized in Other Comprehensive (Income) Loss, After Tax |
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
19. |
Fair Value Measurements |
The fair values of cash and cash equivalents, accounts receivable and accrued
revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments. The fair value of cash in reserve approximates its carrying amount due to the nature of the instrument
held.
Recurring fair value measurements are performed for risk management assets and liabilities and are discussed further in Note 20. These items are
carried at fair value in the Condensed Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the tables below. There have been no transfers between the hierarchy levels during the period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
Level 1 Quoted Prices in Active Markets |
|
|
Level 2 Other Observable Inputs |
|
|
Level 3 Significant Unobservable Inputs |
|
|
Total Fair Value |
|
|
Netting (1) |
|
|
Carrying Amount |
|
Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
$ |
|
|
|
$ |
629 |
|
|
$ |
|
|
|
$ |
629 |
|
|
$ |
(22 |
) |
|
$ |
607 |
|
Long-term |
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
16 |
|
|
|
(3 |
) |
|
|
13 |
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
22 |
|
|
|
13 |
|
|
|
35 |
|
|
|
(22 |
) |
|
|
13 |
|
Long-term |
|
|
|
|
|
|
4 |
|
|
|
11 |
|
|
|
15 |
|
|
|
(3 |
) |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2014 |
|
Level 1 Quoted Prices in Active Markets |
|
|
Level 2 Other Observable Inputs |
|
|
Level 3 Significant Unobservable Inputs |
|
|
Total Fair Value |
|
|
Netting (1) |
|
|
Carrying Amount |
|
Risk Management |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
$ |
|
|
|
$ |
718 |
|
|
$ |
|
|
|
$ |
718 |
|
|
$ |
(11 |
) |
|
$ |
707 |
|
Long-term |
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
67 |
|
|
|
(2 |
) |
|
|
65 |
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
6 |
|
|
|
14 |
|
|
|
11 |
|
|
|
31 |
|
|
|
(11 |
) |
|
|
20 |
|
Long-term |
|
|
|
|
|
|
2 |
|
|
|
7 |
|
|
|
9 |
|
|
|
(2 |
) |
|
|
7 |
|
(1) |
Netting to offset derivative assets and liabilities where the legal right and intention to offset exists, or where counterparty master netting arrangements contain provisions for net settlement. |
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
19. |
Fair Value Measurements (continued) |
The Companys Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed
price contracts and basis swaps with terms to 2018. The fair values of these contracts are based on a market approach and are estimated using inputs which are either directly or indirectly observable at the reporting date, such as exchange and other
published prices, broker quotes and observable trading activity.
Level 3 Fair Value Measurements
As at March 31, 2015, the Companys Level 3 risk management assets and liabilities consist of power purchase contracts with terms to 2017. The fair
values of the power purchase contracts are based on the income approach and are modelled internally using observable and unobservable inputs such as forward power prices in less active markets. The unobservable inputs are obtained from third parties
whenever possible and reviewed by the Company for reasonableness.
Changes in amounts related to risk management assets and liabilities are recognized in
revenues and transportation and processing expense according to their purpose.
A summary of changes in Level 3 fair value measurements for the three
months ended March 31 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Risk Management |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
Balance, Beginning of Year |
|
$ |
(18 |
) |
|
$ |
(7 |
) |
Total Gains (Losses) |
|
|
(11 |
) |
|
|
(1 |
) |
Purchases and Settlements: |
|
|
|
|
|
|
|
|
Purchases |
|
|
|
|
|
|
|
|
Settlements |
|
|
5 |
|
|
|
1 |
|
Transfers in and out of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, End of Period |
|
$ |
(24 |
) |
|
$ |
(7 |
) |
|
|
|
|
|
|
|
|
|
Change in unrealized gains (losses) related to assets and liabilities held at end of period |
|
$ |
(9 |
) |
|
$ |
(1 |
) |
|
|
|
|
|
|
|
|
|
Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:
|
|
|
|
|
|
|
|
|
|
|
Valuation Technique |
|
Unobservable Input |
|
As at March 31, 2015 |
|
As at December 31, 2014 |
Risk Management - Power |
|
Discounted Cash Flow |
|
Forward prices ($/Megawatt Hour) |
|
$35.06 - $39.75 |
|
$40.70 - $48.50 |
A 10 percent increase or decrease in estimated forward power prices would cause a corresponding $4 million ($5 million as at
December 31, 2014) increase or decrease to net risk management assets and liabilities.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
20. |
Financial Instruments and Risk Management |
Encanas financial assets and liabilities are recognized in cash and cash
equivalents, accounts receivable and accrued revenues, cash in reserve, accounts payable and accrued liabilities, risk management assets and liabilities and long-term debt.
B) |
Risk Management Assets and Liabilities |
Risk management assets and liabilities arise from the use of
derivative financial instruments and are measured at fair value. See Note 19 for a discussion of fair value measurements.
Unrealized Risk Management
Position
|
|
|
|
|
|
|
|
|
|
|
As at March 31, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
Current |
|
$ |
607 |
|
|
$ |
707 |
|
Long-term |
|
|
13 |
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
620 |
|
|
|
772 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
Current |
|
|
13 |
|
|
|
20 |
|
Long-term |
|
|
12 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
Net Risk Management Assets |
|
$ |
595 |
|
|
$ |
745 |
|
|
|
|
|
|
|
|
|
|
Commodity Price Positions as at March 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Volumes |
|
|
Term |
|
Average Price |
|
|
Fair Value |
|
Natural Gas Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
|
1,000 MMcf/d |
|
|
2015 |
|
|
4.29 US$/Mcf |
|
|
$ |
413 |
|
|
|
|
|
|
Basis Contracts (1) |
|
|
|
|
|
2015-2018 |
|
|
|
|
|
|
62 |
|
|
|
|
|
|
Other Financial Positions |
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Fixed Price |
|
|
55.8 Mbbls/d |
|
|
2015 |
|
|
62.09 US$/bbl |
|
|
|
146 |
|
WTI Fixed Price |
|
|
1.2 Mbbls/d |
|
|
2016 |
|
|
92.35 US$/bbl |
|
|
|
16 |
|
|
|
|
|
|
Basis Contracts (2) |
|
|
|
|
|
2015-2016 |
|
|
|
|
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power Purchase Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
$ |
595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Encana has entered into swaps to protect against widening natural gas price differentials between benchmark and regional sales prices. These basis swaps are priced using differentials determined as a percentage of
NYMEX. |
(2) |
Encana has entered into swaps to protect against widening Brent and Midland differentials to WTI. These basis swaps are priced using fixed price differentials. |
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
20. |
Financial Instruments and Risk Management (continued) |
B) |
Risk Management Assets and Liabilities (continued) |
Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain (Loss) |
|
|
Unrealized Gain (Loss) |
|
|
|
Three Months Ended March 31, |
|
|
Three Months Ended March 31, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
245 |
|
|
$ |
(140 |
) |
|
$ |
(128 |
) |
|
$ |
(284 |
) |
Transportation and Processing |
|
|
(5 |
) |
|
|
(1 |
) |
|
|
(8 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) on Risk Management |
|
$ |
240 |
|
|
$ |
(141 |
) |
|
$ |
(136 |
) |
|
$ |
(285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Unrealized Risk Management Positions from January 1 to March 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
Fair Value |
|
|
Total Unrealized Gain (Loss) |
|
|
Total Unrealized Gain (Loss) |
|
|
|
|
|
Fair Value of Contracts, Beginning of Year |
|
$ |
745 |
|
|
|
|
|
|
|
|
|
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Period |
|
|
104 |
|
|
$ |
104 |
|
|
$ |
(426 |
) |
Foreign Exchange Translation Adjustment on Canadian Dollar Contracts |
|
|
2 |
|
|
|
|
|
|
|
|
|
Settlement of Athlon Crude Oil Contracts from Business Combination |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
Fair Value of Contracts Realized During the Period |
|
|
(240 |
) |
|
|
(240 |
) |
|
|
141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts, End of Period |
|
$ |
595 |
|
|
$ |
(136 |
) |
|
$ |
(285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
C) |
Risks Associated with Financial Assets and Liabilities |
The Company is exposed to financial risks
including market risks (such as commodity prices, foreign exchange and interest rates), credit risk and liquidity risk. Future cash flows may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.
Commodity Price Risk
Commodity price risk arises from
the effect fluctuations in future commodity prices may have on future cash flows. To partially mitigate exposure to commodity price risk, the Company has entered into various derivative financial instruments. The use of these derivative instruments
is governed under formal policies and is subject to limits established by the Board of Directors. The Companys policy is to not use derivative financial instruments for speculative purposes.
Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses contracts such as NYMEX-based swaps and options. Encana also enters
into basis swaps to manage against widening price differentials between various production areas and various sales points.
Crude Oil - To partially
mitigate against crude oil commodity price risk including widening price differentials between North American and world prices, the Company has entered into fixed price contracts and basis swaps.
Power - The Company has entered into Canadian dollar denominated derivative contracts to manage its electricity consumption costs.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
20. |
Financial Instruments and Risk Management (continued) |
C) |
Risks Associated with Financial Assets and Liabilities (continued) |
Commodity Price Risk (continued)
The table below summarizes the sensitivity of the fair value of the Companys risk management positions
to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized
gains (losses) impacting pre-tax net earnings for the three months ended March 31 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
10% Price Increase |
|
|
10% Price Decrease |
|
|
10% Price Increase |
|
|
10% Price Decrease |
|
|
|
|
|
|
Natural Gas Price |
|
$ |
(70 |
) |
|
$ |
70 |
|
|
$ |
(385 |
) |
|
$ |
385 |
|
Crude Oil Price |
|
|
(78 |
) |
|
|
78 |
|
|
|
(29 |
) |
|
|
29 |
|
Power Price |
|
|
4 |
|
|
|
(4 |
) |
|
|
7 |
|
|
|
(7 |
) |
Credit Risk
Credit risk
arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit
policies governing the Companys credit portfolio including credit practices that limit transactions according to counterparties credit quality. Mitigation strategies may include master netting arrangements, requesting collateral and/or
transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As at March 31, 2015, the Company had
no significant collateral balances posted or received and there were no credit derivatives in place.
As at March 31, 2015, cash equivalents include
high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions in Canada and the U.S. or with
counterparties having investment grade credit ratings.
A substantial portion of the Companys accounts receivable are with customers in the oil and
gas industry and are subject to normal industry credit risks. As at March 31, 2015, approximately 94 percent (94 percent as at December 31, 2014) of Encanas accounts receivable and financial derivative credit exposures were with
investment grade counterparties.
As at March 31, 2015, Encana had three counterparties (three counterparties as at December 31, 2014) whose net
settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. As at March 31, 2015, these counterparties accounted for 17 percent, 15 percent
and 14 percent (16 percent, 16 percent and 15 percent as at December 31, 2014) of the fair value of the outstanding in-the-money net risk management contracts.
Liquidity Risk
Liquidity risk arises from the potential
that the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages liquidity risk using cash and debt management programs.
The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities and
debt and equity capital markets. As at March 31, 2015, the Company had committed revolving bank credit facilities totaling $3.8 billion which include C$3.5 billion ($2.8 billion) on a revolving bank credit facility for Encana and $1.0 billion
on a revolving bank credit facility for a U.S. subsidiary, the latter of which remains unused. Of the C$3.5 billion ($2.8 billion) revolving bank credit facility, $1.6 billion remained unused. The facilities remain committed through June 2018.
Encana also has accessible capacity under a shelf prospectus for up to $4.9 billion, or the equivalent in foreign currencies, the availability of which is
dependent on market conditions, to issue debt and/or equity securities in Canada and/or the U.S. The shelf prospectus expires in July 2016.
The Company
believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
20. |
Financial Instruments and Risk Management (continued) |
C) |
Risks Associated with Financial Assets and Liabilities (continued) |
Liquidity Risk (continued)
The Company minimizes its liquidity risk by managing its capital structure. The Companys capital
structure consists of shareholders equity plus long-term debt, including the current portion. The Companys objectives when managing its capital structure are to maintain financial flexibility to preserve Encanas access to capital
markets and its ability to meet financial obligations and to finance internally generated growth as well as potential acquisitions. To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders,
issue new shares, issue new debt or repay existing debt.
The timing of expected cash outflows relating to financial liabilities is outlined in the table
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than 1 Year |
|
|
1 -3 Years |
|
|
4 -5 Years |
|
|
6 - 9 Years |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Liabilities |
|
$ |
1,903 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,903 |
|
Risk Management Liabilities |
|
|
13 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
Long-Term Debt (1) |
|
|
1,823 |
|
|
|
610 |
|
|
|
2,295 |
|
|
|
1,610 |
|
|
|
6,313 |
|
|
|
12,651 |
|
(1) |
Principal and interest. |
Included in Encanas long-term debt obligations of $12,651 million at
March 31, 2015 are $1,211 million in principal obligations for revolving credit and term loan borrowings related to U.S. Commercial Paper. These amounts are fully supported and Management expects they will continue to be supported by revolving
credit facilities that have no repayment requirements within the next year. The revolving credit facilities are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, these amounts are
included in cash outflows for the period disclosed as 4 - 5 Years. Further information on Long-Term Debt is contained in Note 10.
Foreign Exchange
Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Companys
financial assets or liabilities. As Encana operates primarily in North America, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Companys reported results. Encanas financial
results are consolidated in Canadian dollars; however, the Company reports its results in U.S. dollars as most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas
companies. As the effects of foreign exchange fluctuations are embedded in the Companys results, the total effect of foreign exchange fluctuations is not separately identifiable.
To mitigate the exposure to the fluctuating U.S./Canadian dollar exchange rate, Encana maintains a mix of both U.S. dollar and Canadian dollar debt and may
also enter into foreign exchange derivatives. As at March 31, 2015, Encana had $6.6 billion in U.S. dollar debt issued from Canada that was subject to foreign exchange exposure ($6.7 billion as at December 31, 2014) and $0.6 billion in
debt that was not subject to foreign exchange exposure ($0.6 billion as at December 31, 2014). There were no foreign exchange derivatives outstanding as at March 31, 2015.
Encanas foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated debt
issued from Canada, unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated risk management assets and liabilities held in Canada and foreign exchange gains and losses on U.S. dollar denominated cash and short-term
investments held in Canada. A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $48 million change in foreign exchange (gain) loss as at March 31, 2015 (2014 - $48 million).
Interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Companys financial assets or
liabilities. The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt and may also enter into interest rate derivatives to partially mitigate effects of fluctuations in market
interest rates. There were no interest rate derivatives outstanding as at March 31, 2015.
As at March 31, 2015, the Company had floating rate
debt of $1,211 million. Accordingly, the sensitivity in net earnings for each one percent change in interest rates on floating rate debt was $9 million (2014 - nil).
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Q1 Report | for the period ended March 31, 2015
Notes to Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
21. |
Commitments and Contingencies |
Commitments
The following table outlines the Companys commitments as at March 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Payments |
|
(undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
598 |
|
|
$ |
787 |
|
|
$ |
779 |
|
|
$ |
798 |
|
|
$ |
674 |
|
|
$ |
3,085 |
|
|
$ |
6,721 |
|
Drilling and Field Services |
|
|
164 |
|
|
|
128 |
|
|
|
90 |
|
|
|
47 |
|
|
|
14 |
|
|
|
16 |
|
|
|
459 |
|
Operating Leases |
|
|
24 |
|
|
|
27 |
|
|
|
22 |
|
|
|
21 |
|
|
|
8 |
|
|
|
20 |
|
|
|
122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
786 |
|
|
$ |
942 |
|
|
$ |
891 |
|
|
$ |
866 |
|
|
$ |
696 |
|
|
$ |
3,121 |
|
|
$ |
7,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included within transportation and processing in the table above are certain commitments associated with midstream service
agreements with VMLP as described in Note 15.
Contingencies
Encana is involved in various legal claims and actions arising in the course of the Companys operations. Although the outcome of these claims cannot be
predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encanas financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of
a material adverse impact on the Companys consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable and the amount
can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Supplemental Financial Information (unaudited)
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions, except per share amounts) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Cash Flow (1) |
|
|
495 |
|
|
|
2,934 |
|
|
|
377 |
|
|
|
807 |
|
|
|
656 |
|
|
|
1,094 |
|
Per share - Diluted (3) |
|
|
0.65 |
|
|
|
3.96 |
|
|
|
0.51 |
|
|
|
1.09 |
|
|
|
0.89 |
|
|
|
1.48 |
|
|
|
|
|
|
|
|
Operating Earnings (2) |
|
|
9 |
|
|
|
1,002 |
|
|
|
35 |
|
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
Per share - Diluted (3) |
|
|
0.01 |
|
|
|
1.35 |
|
|
|
0.05 |
|
|
|
0.38 |
|
|
|
0.23 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(1,707 |
) |
|
|
3,392 |
|
|
|
198 |
|
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
Per share - Diluted (3) |
|
|
(2.25 |
) |
|
|
4.58 |
|
|
|
0.27 |
|
|
|
3.79 |
|
|
|
0.37 |
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective Tax Rate using Canadian Statutory Rate |
|
|
25.7 |
% |
|
|
25.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Rates (US$ per C$1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
0.806 |
|
|
|
0.905 |
|
|
|
0.881 |
|
|
|
0.918 |
|
|
|
0.917 |
|
|
|
0.906 |
|
Period end |
|
|
0.789 |
|
|
|
0.862 |
|
|
|
0.862 |
|
|
|
0.892 |
|
|
|
0.937 |
|
|
|
0.905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Summary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
|
482 |
|
|
|
2,667 |
|
|
|
261 |
|
|
|
696 |
|
|
|
767 |
|
|
|
943 |
|
Deduct (Add back): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
(7 |
) |
|
|
(43 |
) |
|
|
(15 |
) |
|
|
(11 |
) |
|
|
(8 |
) |
|
|
(9 |
) |
Net change in non-cash working capital |
|
|
(6 |
) |
|
|
(9 |
) |
|
|
(141 |
) |
|
|
155 |
|
|
|
119 |
|
|
|
(142 |
) |
Cash tax on sale of assets |
|
|
|
|
|
|
(215 |
) |
|
|
40 |
|
|
|
(255 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow (1) |
|
|
495 |
|
|
|
2,934 |
|
|
|
377 |
|
|
|
807 |
|
|
|
656 |
|
|
|
1,094 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings Summary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(1,707 |
) |
|
|
3,392 |
|
|
|
198 |
|
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
After-tax (addition) deduction: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
|
(98 |
) |
|
|
306 |
|
|
|
341 |
|
|
|
160 |
|
|
|
8 |
|
|
|
(203 |
) |
Impairments |
|
|
(1,222 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring charges |
|
|
|
|
|
|
(24 |
) |
|
|
(4 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(10 |
) |
Non-operating foreign exchange gain (loss) |
|
|
(508 |
) |
|
|
(407 |
) |
|
|
(151 |
) |
|
|
(218 |
) |
|
|
156 |
|
|
|
(194 |
) |
Gain (loss) on divestitures |
|
|
10 |
|
|
|
2,523 |
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
|
|
Income tax adjustments |
|
|
102 |
|
|
|
(8 |
) |
|
|
(12 |
) |
|
|
190 |
|
|
|
(194 |
) |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (2) |
|
|
9 |
|
|
|
1,002 |
|
|
|
35 |
|
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets. |
(2) |
Operating Earnings is a non-GAAP measure defined as net earnings attributable to common shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Companys
financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income
taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate. |
(3) |
Net earnings attributable to common shareholders, operating earnings and cash flow per common share are calculated using the weighted average number of Encana common shares outstanding as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(millions) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
757.8 |
|
|
|
741.0 |
|
|
|
741.1 |
|
|
|
741.1 |
|
|
|
741.0 |
|
|
|
741.0 |
|
Diluted |
|
|
757.8 |
|
|
|
741.0 |
|
|
|
741.1 |
|
|
|
741.1 |
|
|
|
741.0 |
|
|
|
741.0 |
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
Q1 Report | for the period ended March 31, 2015
Supplemental Financial & Operating Information (unaudited)
Financial Metrics
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Q1 |
|
|
Year |
|
|
|
|
Debt to Debt Adjusted Cash Flow |
|
|
2.6x |
|
|
|
2.1x |
|
|
|
|
Debt to Adjusted Capitalization |
|
|
29 |
% |
|
|
30 |
% |
The financial metrics disclosed above are non-GAAP measures monitored by Management as indicators of the Companys
overall financial strength. These non-GAAP measures are defined and calculated in the Non-GAAP Measures section of Encanas Managements Discussion and Analysis.
Net Capital Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Capital Investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
151 |
|
|
|
1,226 |
|
|
|
302 |
|
|
|
293 |
|
|
|
350 |
|
|
|
281 |
|
USA Operations |
|
|
583 |
|
|
|
1,285 |
|
|
|
548 |
|
|
|
305 |
|
|
|
206 |
|
|
|
226 |
|
Market Optimization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
1 |
|
|
|
1 |
|
Corporate & Other |
|
|
2 |
|
|
|
15 |
|
|
|
7 |
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
736 |
|
|
|
2,526 |
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Acquisitions & (Divestitures) |
|
|
(838 |
) |
|
|
(1,329 |
) |
|
|
50 |
|
|
|
(2,007 |
) |
|
|
652 |
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Capital Investment |
|
|
(102 |
) |
|
|
1,197 |
|
|
|
907 |
|
|
|
(1,409 |
) |
|
|
1,212 |
|
|
|
487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Capital Investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
79 |
|
|
|
781 |
|
|
|
159 |
|
|
|
204 |
|
|
|
210 |
|
|
|
208 |
|
Duvernay |
|
|
70 |
|
|
|
328 |
|
|
|
118 |
|
|
|
58 |
|
|
|
81 |
|
|
|
71 |
|
Eagle Ford |
|
|
197 |
|
|
|
274 |
|
|
|
149 |
|
|
|
113 |
|
|
|
12 |
|
|
|
|
|
Permian |
|
|
217 |
|
|
|
117 |
|
|
|
117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin |
|
|
88 |
|
|
|
277 |
|
|
|
81 |
|
|
|
68 |
|
|
|
69 |
|
|
|
59 |
|
San Juan |
|
|
36 |
|
|
|
287 |
|
|
|
96 |
|
|
|
89 |
|
|
|
50 |
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
687 |
|
|
|
2,064 |
|
|
|
720 |
|
|
|
532 |
|
|
|
422 |
|
|
|
390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Upstream Operations (1, 2) |
|
|
47 |
|
|
|
447 |
|
|
|
130 |
|
|
|
66 |
|
|
|
134 |
|
|
|
117 |
|
Market Optimization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
1 |
|
|
|
1 |
|
Corporate & Other |
|
|
2 |
|
|
|
15 |
|
|
|
7 |
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
736 |
|
|
|
2,526 |
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Montney has been realigned to include certain capital investments which were previously reported in Other Upstream Operations. |
(2) |
Other Upstream Operations includes capital investment for Encanas base production properties as well as capital investment for prospective plays which are under appraisal, including the Tuscaloosa Marine Shale
(TMS). Q1 2015 capital investment for the TMS was $26 million (Q1 2014 - $20 million). |
|
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Supplemental Financial & Operating Information (unaudited)
Production Volumes - After Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(average) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,857 |
|
|
|
2,350 |
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
79.2 |
|
|
|
49.4 |
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
NGLs (Mbbls/d) |
|
|
41.5 |
|
|
|
37.4 |
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs (Mbbls/d) |
|
|
120.7 |
|
|
|
86.8 |
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBOE/d) |
|
|
430.1 |
|
|
|
478.5 |
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes - After Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(average) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
1,128 |
|
|
|
1,378 |
|
|
|
1,111 |
|
|
|
1,374 |
|
|
|
1,463 |
|
|
|
1,568 |
|
USA Operations |
|
|
729 |
|
|
|
972 |
|
|
|
750 |
|
|
|
825 |
|
|
|
1,078 |
|
|
|
1,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,857 |
|
|
|
2,350 |
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
6.6 |
|
|
|
13.6 |
|
|
|
9.4 |
|
|
|
14.7 |
|
|
|
13.9 |
|
|
|
16.4 |
|
USA Operations |
|
|
72.6 |
|
|
|
35.8 |
|
|
|
59.4 |
|
|
|
47.4 |
|
|
|
20.3 |
|
|
|
15.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79.2 |
|
|
|
49.4 |
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
21.2 |
|
|
|
23.6 |
|
|
|
18.8 |
|
|
|
27.6 |
|
|
|
23.5 |
|
|
|
24.6 |
|
USA Operations |
|
|
20.3 |
|
|
|
13.8 |
|
|
|
18.8 |
|
|
|
14.3 |
|
|
|
10.5 |
|
|
|
11.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41.5 |
|
|
|
37.4 |
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
27.8 |
|
|
|
37.2 |
|
|
|
28.2 |
|
|
|
42.3 |
|
|
|
37.4 |
|
|
|
41.0 |
|
USA Operations |
|
|
92.9 |
|
|
|
49.6 |
|
|
|
78.2 |
|
|
|
61.7 |
|
|
|
30.8 |
|
|
|
26.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120.7 |
|
|
|
86.8 |
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBOE/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
215.8 |
|
|
|
266.9 |
|
|
|
213.4 |
|
|
|
271.4 |
|
|
|
281.4 |
|
|
|
302.4 |
|
USA Operations |
|
|
214.3 |
|
|
|
211.6 |
|
|
|
203.3 |
|
|
|
199.2 |
|
|
|
210.4 |
|
|
|
233.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
430.1 |
|
|
|
478.5 |
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs Production Volumes - After Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(average Mbbls/d) |
|
Q1 |
|
|
% of Total |
|
|
Year |
|
|
% of Total |
|
Oil |
|
|
79.2 |
|
|
|
66 |
|
|
|
49.4 |
|
|
|
57 |
|
Plant Condensate |
|
|
14.0 |
|
|
|
11 |
|
|
|
12.0 |
|
|
|
14 |
|
Butane |
|
|
7.2 |
|
|
|
6 |
|
|
|
6.8 |
|
|
|
8 |
|
Propane |
|
|
9.7 |
|
|
|
8 |
|
|
|
10.2 |
|
|
|
11 |
|
Ethane |
|
|
10.6 |
|
|
|
9 |
|
|
|
8.4 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120.7 |
|
|
|
100 |
|
|
|
86.8 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
Q1 Report | for the period ended March 31, 2015
Supplemental Financial & Operating Information (unaudited)
Results of Operations
Product and Operational Information, Including the Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas - Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
396 |
|
|
|
2,468 |
|
|
|
402 |
|
|
|
480 |
|
|
|
569 |
|
|
|
1,017 |
|
Realized Financial Hedging Gain (Loss) |
|
|
154 |
|
|
|
(74 |
) |
|
|
25 |
|
|
|
20 |
|
|
|
(44 |
) |
|
|
(75 |
) |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
5 |
|
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
2 |
|
Transportation and processing |
|
|
163 |
|
|
|
773 |
|
|
|
177 |
|
|
|
186 |
|
|
|
209 |
|
|
|
201 |
|
Operating |
|
|
36 |
|
|
|
279 |
|
|
|
57 |
|
|
|
66 |
|
|
|
72 |
|
|
|
84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
351 |
|
|
|
1,337 |
|
|
|
191 |
|
|
|
247 |
|
|
|
244 |
|
|
|
655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
195 |
|
|
|
1,640 |
|
|
|
274 |
|
|
|
307 |
|
|
|
463 |
|
|
|
596 |
|
Realized Financial Hedging Gain (Loss) |
|
|
54 |
|
|
|
(85 |
) |
|
|
13 |
|
|
|
10 |
|
|
|
(43 |
) |
|
|
(65 |
) |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
4 |
|
|
|
44 |
|
|
|
11 |
|
|
|
(10 |
) |
|
|
14 |
|
|
|
29 |
|
Transportation and processing |
|
|
151 |
|
|
|
651 |
|
|
|
149 |
|
|
|
162 |
|
|
|
177 |
|
|
|
163 |
|
Operating |
|
|
49 |
|
|
|
235 |
|
|
|
52 |
|
|
|
50 |
|
|
|
65 |
|
|
|
68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
45 |
|
|
|
625 |
|
|
|
75 |
|
|
|
115 |
|
|
|
164 |
|
|
|
271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - Total Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
591 |
|
|
|
4,108 |
|
|
|
676 |
|
|
|
787 |
|
|
|
1,032 |
|
|
|
1,613 |
|
Realized Financial Hedging Gain (Loss) |
|
|
208 |
|
|
|
(159 |
) |
|
|
38 |
|
|
|
30 |
|
|
|
(87 |
) |
|
|
(140 |
) |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
4 |
|
|
|
49 |
|
|
|
13 |
|
|
|
(9 |
) |
|
|
14 |
|
|
|
31 |
|
Transportation and processing |
|
|
314 |
|
|
|
1,424 |
|
|
|
326 |
|
|
|
348 |
|
|
|
386 |
|
|
|
364 |
|
Operating |
|
|
85 |
|
|
|
514 |
|
|
|
109 |
|
|
|
116 |
|
|
|
137 |
|
|
|
152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
396 |
|
|
|
1,962 |
|
|
|
266 |
|
|
|
362 |
|
|
|
408 |
|
|
|
926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs - Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
77 |
|
|
|
872 |
|
|
|
149 |
|
|
|
251 |
|
|
|
227 |
|
|
|
245 |
|
Realized Financial Hedging Gain (Loss) |
|
|
2 |
|
|
|
18 |
|
|
|
24 |
|
|
|
(1 |
) |
|
|
(5 |
) |
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
3 |
|
|
|
4 |
|
|
|
3 |
|
Transportation and processing |
|
|
14 |
|
|
|
62 |
|
|
|
16 |
|
|
|
16 |
|
|
|
16 |
|
|
|
14 |
|
Operating |
|
|
6 |
|
|
|
28 |
|
|
|
10 |
|
|
|
8 |
|
|
|
4 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
59 |
|
|
|
790 |
|
|
|
147 |
|
|
|
223 |
|
|
|
198 |
|
|
|
222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs - USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
295 |
|
|
|
1,258 |
|
|
|
412 |
|
|
|
452 |
|
|
|
215 |
|
|
|
179 |
|
Realized Financial Hedging Gain (Loss) |
|
|
38 |
|
|
|
60 |
|
|
|
65 |
|
|
|
1 |
|
|
|
(6 |
) |
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
15 |
|
|
|
74 |
|
|
|
23 |
|
|
|
23 |
|
|
|
15 |
|
|
|
13 |
|
Transportation and processing |
|
|
4 |
|
|
|
7 |
|
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
Operating |
|
|
75 |
|
|
|
115 |
|
|
|
51 |
|
|
|
44 |
|
|
|
12 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
239 |
|
|
|
1,122 |
|
|
|
400 |
|
|
|
382 |
|
|
|
182 |
|
|
|
158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs - Total Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
372 |
|
|
|
2,130 |
|
|
|
561 |
|
|
|
703 |
|
|
|
442 |
|
|
|
424 |
|
Realized Financial Hedging Gain (Loss) |
|
|
40 |
|
|
|
78 |
|
|
|
89 |
|
|
|
|
|
|
|
(11 |
) |
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
15 |
|
|
|
84 |
|
|
|
23 |
|
|
|
26 |
|
|
|
19 |
|
|
|
16 |
|
Transportation and processing |
|
|
18 |
|
|
|
69 |
|
|
|
19 |
|
|
|
20 |
|
|
|
16 |
|
|
|
14 |
|
Operating |
|
|
81 |
|
|
|
143 |
|
|
|
61 |
|
|
|
52 |
|
|
|
16 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
298 |
|
|
|
1,912 |
|
|
|
547 |
|
|
|
605 |
|
|
|
380 |
|
|
|
380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Supplemental Oil and Gas Operating Statistics (unaudited)
Operating Statistics - After Royalties
Per-unit Results, Excluding the Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas - Canadian Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price (1) |
|
|
3.89 |
|
|
|
4.89 |
|
|
|
3.93 |
|
|
|
3.78 |
|
|
|
4.27 |
|
|
|
7.17 |
|
Production and mineral taxes |
|
|
|
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
|
|
|
|
0.01 |
|
Transportation and processing |
|
|
1.60 |
|
|
|
1.53 |
|
|
|
1.73 |
|
|
|
1.47 |
|
|
|
1.57 |
|
|
|
1.42 |
|
Operating |
|
|
0.35 |
|
|
|
0.55 |
|
|
|
0.55 |
|
|
|
0.52 |
|
|
|
0.55 |
|
|
|
0.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
1.94 |
|
|
|
2.80 |
|
|
|
1.64 |
|
|
|
1.78 |
|
|
|
2.15 |
|
|
|
5.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - USA Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
2.97 |
|
|
|
4.62 |
|
|
|
3.95 |
|
|
|
4.05 |
|
|
|
4.72 |
|
|
|
5.34 |
|
Production and mineral taxes |
|
|
0.06 |
|
|
|
0.12 |
|
|
|
0.17 |
|
|
|
(0.14 |
) |
|
|
0.15 |
|
|
|
0.26 |
|
Transportation and processing |
|
|
2.30 |
|
|
|
1.83 |
|
|
|
2.16 |
|
|
|
2.13 |
|
|
|
1.80 |
|
|
|
1.46 |
|
Operating |
|
|
0.75 |
|
|
|
0.66 |
|
|
|
0.75 |
|
|
|
0.65 |
|
|
|
0.67 |
|
|
|
0.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
(0.14 |
) |
|
|
2.01 |
|
|
|
0.87 |
|
|
|
1.41 |
|
|
|
2.10 |
|
|
|
3.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - Total Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price (2) |
|
|
3.53 |
|
|
|
4.78 |
|
|
|
3.94 |
|
|
|
3.88 |
|
|
|
4.46 |
|
|
|
6.37 |
|
Production and mineral taxes |
|
|
0.02 |
|
|
|
0.06 |
|
|
|
0.08 |
|
|
|
(0.05 |
) |
|
|
0.06 |
|
|
|
0.12 |
|
Transportation and processing |
|
|
1.88 |
|
|
|
1.66 |
|
|
|
1.90 |
|
|
|
1.72 |
|
|
|
1.67 |
|
|
|
1.44 |
|
Operating |
|
|
0.51 |
|
|
|
0.60 |
|
|
|
0.63 |
|
|
|
0.57 |
|
|
|
0.60 |
|
|
|
0.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
1.12 |
|
|
|
2.46 |
|
|
|
1.33 |
|
|
|
1.64 |
|
|
|
2.13 |
|
|
|
4.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs - Canadian Operations ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
30.65 |
|
|
|
64.16 |
|
|
|
57.50 |
|
|
|
64.79 |
|
|
|
66.13 |
|
|
|
66.36 |
|
Production and mineral taxes |
|
|
0.04 |
|
|
|
0.71 |
|
|
|
0.10 |
|
|
|
0.67 |
|
|
|
1.12 |
|
|
|
0.80 |
|
Transportation and processing |
|
|
5.82 |
|
|
|
4.52 |
|
|
|
5.92 |
|
|
|
4.21 |
|
|
|
4.60 |
|
|
|
3.80 |
|
Operating |
|
|
2.31 |
|
|
|
2.09 |
|
|
|
4.00 |
|
|
|
2.05 |
|
|
|
1.06 |
|
|
|
1.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
22.48 |
|
|
|
56.84 |
|
|
|
47.48 |
|
|
|
57.86 |
|
|
|
59.35 |
|
|
|
60.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs - USA Operations ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
35.18 |
|
|
|
69.54 |
|
|
|
57.30 |
|
|
|
79.43 |
|
|
|
77.46 |
|
|
|
73.61 |
|
Production and mineral taxes |
|
|
1.80 |
|
|
|
4.10 |
|
|
|
3.16 |
|
|
|
4.18 |
|
|
|
5.19 |
|
|
|
5.46 |
|
Transportation and processing |
|
|
0.43 |
|
|
|
0.39 |
|
|
|
0.49 |
|
|
|
0.63 |
|
|
|
|
|
|
|
|
|
Operating |
|
|
8.96 |
|
|
|
6.36 |
|
|
|
7.11 |
|
|
|
7.80 |
|
|
|
4.29 |
|
|
|
3.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
23.99 |
|
|
|
58.69 |
|
|
|
46.54 |
|
|
|
66.82 |
|
|
|
67.98 |
|
|
|
64.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs - Total Operations ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
34.13 |
|
|
|
67.24 |
|
|
|
57.35 |
|
|
|
73.48 |
|
|
|
71.23 |
|
|
|
69.23 |
|
Production and mineral taxes |
|
|
1.40 |
|
|
|
2.65 |
|
|
|
2.35 |
|
|
|
2.75 |
|
|
|
2.95 |
|
|
|
2.65 |
|
Transportation and processing |
|
|
1.67 |
|
|
|
2.16 |
|
|
|
1.93 |
|
|
|
2.09 |
|
|
|
2.53 |
|
|
|
2.30 |
|
Operating |
|
|
7.43 |
|
|
|
4.54 |
|
|
|
6.29 |
|
|
|
5.46 |
|
|
|
2.51 |
|
|
|
2.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
23.63 |
|
|
|
57.89 |
|
|
|
46.78 |
|
|
|
63.18 |
|
|
|
63.24 |
|
|
|
61.97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operations Netback - Canadian Operations ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
24.30 |
|
|
|
34.21 |
|
|
|
28.06 |
|
|
|
29.21 |
|
|
|
31.02 |
|
|
|
46.20 |
|
Production and mineral taxes |
|
|
0.02 |
|
|
|
0.15 |
|
|
|
0.09 |
|
|
|
0.15 |
|
|
|
0.16 |
|
|
|
0.18 |
|
Transportation and processing |
|
|
9.12 |
|
|
|
8.55 |
|
|
|
9.79 |
|
|
|
8.10 |
|
|
|
8.76 |
|
|
|
7.87 |
|
Operating |
|
|
2.14 |
|
|
|
3.14 |
|
|
|
3.39 |
|
|
|
2.96 |
|
|
|
2.98 |
|
|
|
3.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
13.02 |
|
|
|
22.37 |
|
|
|
14.79 |
|
|
|
18.00 |
|
|
|
19.12 |
|
|
|
34.86 |
|
Total Operations Netback - USA Operations ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
25.34 |
|
|
|
37.53 |
|
|
|
36.64 |
|
|
|
41.38 |
|
|
|
35.48 |
|
|
|
36.82 |
|
Production and mineral taxes |
|
|
0.97 |
|
|
|
1.53 |
|
|
|
1.84 |
|
|
|
0.72 |
|
|
|
1.51 |
|
|
|
1.99 |
|
Transportation and processing |
|
|
8.02 |
|
|
|
8.52 |
|
|
|
8.17 |
|
|
|
9.03 |
|
|
|
9.23 |
|
|
|
7.75 |
|
Operating |
|
|
6.44 |
|
|
|
4.53 |
|
|
|
5.51 |
|
|
|
5.12 |
|
|
|
4.05 |
|
|
|
3.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
9.91 |
|
|
|
22.95 |
|
|
|
21.12 |
|
|
|
26.51 |
|
|
|
20.69 |
|
|
|
23.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operations Netback ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
24.82 |
|
|
|
35.67 |
|
|
|
32.25 |
|
|
|
34.36 |
|
|
|
32.93 |
|
|
|
42.12 |
|
Production and mineral taxes |
|
|
0.49 |
|
|
|
0.76 |
|
|
|
0.94 |
|
|
|
0.39 |
|
|
|
0.74 |
|
|
|
0.97 |
|
Transportation and processing |
|
|
8.57 |
|
|
|
8.54 |
|
|
|
9.00 |
|
|
|
8.50 |
|
|
|
8.96 |
|
|
|
7.82 |
|
Operating (3) |
|
|
4.27 |
|
|
|
3.76 |
|
|
|
4.43 |
|
|
|
3.87 |
|
|
|
3.44 |
|
|
|
3.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback |
|
|
11.49 |
|
|
|
22.61 |
|
|
|
17.88 |
|
|
|
21.60 |
|
|
|
19.79 |
|
|
|
29.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Canadian Operations price reflects Deep Panuke price for Q1 2015 of $10.68/Mcf on natural gas production volumes of 182 MMcf/d. Excluding the impact of the Deep Panuke operations, the natural gas price for Q1 2015 is
$2.59/Mcf. |
(2) |
Excluding the impact of the Deep Panuke operations, the natural gas price for Q1 2015 is $2.76/Mcf. |
(3) |
Q1 2015 operating expense includes a recovery of costs related to long-term incentives of $0.04/B0E (Q1 2014 - costs of $0.32/B0E). |
|
|
|
|
|
Supplemental Information Prepared in US$ |
Q1 Report | for the period ended March 31, 2015
Supplemental Oil and Gas Operating Statistics (unaudited)
Operating Statistics - After Royalties (continued)
Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
1.52 |
|
|
|
(0.15 |
) |
|
|
0.24 |
|
|
|
0.16 |
|
|
|
(0.33 |
) |
|
|
(0.53 |
) |
USA Operations |
|
|
0.82 |
|
|
|
(0.24 |
) |
|
|
0.19 |
|
|
|
0.12 |
|
|
|
(0.44 |
) |
|
|
(0.58 |
) |
Total Operations |
|
|
1.25 |
|
|
|
(0.19 |
) |
|
|
0.22 |
|
|
|
0.15 |
|
|
|
(0.38 |
) |
|
|
(0.55 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
0.78 |
|
|
|
1.36 |
|
|
|
9.35 |
|
|
|
(0.31 |
) |
|
|
(1.22 |
) |
|
|
(0.09 |
) |
USA Operations |
|
|
4.58 |
|
|
|
3.29 |
|
|
|
8.94 |
|
|
|
0.25 |
|
|
|
(2.28 |
) |
|
|
0.04 |
|
Total Operations |
|
|
3.70 |
|
|
|
2.46 |
|
|
|
9.05 |
|
|
|
0.02 |
|
|
|
(1.70 |
) |
|
|
(0.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
8.04 |
|
|
|
(0.57 |
) |
|
|
2.49 |
|
|
|
0.78 |
|
|
|
(1.89 |
) |
|
|
(2.77 |
) |
USA Operations |
|
|
4.78 |
|
|
|
(0.33 |
) |
|
|
4.15 |
|
|
|
0.58 |
|
|
|
(2.57 |
) |
|
|
(3.07 |
) |
Total Operations |
|
|
6.42 |
|
|
|
(0.46 |
) |
|
|
3.30 |
|
|
|
0.70 |
|
|
|
(2.18 |
) |
|
|
(2.90 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per-unit Results, Including the Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas Price ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
5.41 |
|
|
|
4.74 |
|
|
|
4.17 |
|
|
|
3.94 |
|
|
|
3.94 |
|
|
|
6.64 |
|
USA Operations |
|
|
3.79 |
|
|
|
4.38 |
|
|
|
4.14 |
|
|
|
4.17 |
|
|
|
4.28 |
|
|
|
4.76 |
|
Total Operations |
|
|
4.78 |
|
|
|
4.59 |
|
|
|
4.16 |
|
|
|
4.03 |
|
|
|
4.08 |
|
|
|
5.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Netback ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
3.46 |
|
|
|
2.65 |
|
|
|
1.88 |
|
|
|
1.94 |
|
|
|
1.82 |
|
|
|
4.62 |
|
USA Operations |
|
|
0.68 |
|
|
|
1.77 |
|
|
|
1.06 |
|
|
|
1.53 |
|
|
|
1.66 |
|
|
|
2.43 |
|
Total Operations |
|
|
2.37 |
|
|
|
2.27 |
|
|
|
1.55 |
|
|
|
1.79 |
|
|
|
1.75 |
|
|
|
3.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs Price ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
31.43 |
|
|
|
65.52 |
|
|
|
66.85 |
|
|
|
64.48 |
|
|
|
64.91 |
|
|
|
66.27 |
|
USA Operations |
|
|
39.76 |
|
|
|
72.83 |
|
|
|
66.24 |
|
|
|
79.68 |
|
|
|
75.18 |
|
|
|
73.65 |
|
Total Operations |
|
|
37.83 |
|
|
|
69.70 |
|
|
|
66.40 |
|
|
|
73.50 |
|
|
|
69.53 |
|
|
|
69.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs Netback ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
23.26 |
|
|
|
58.20 |
|
|
|
56.83 |
|
|
|
57.55 |
|
|
|
58.13 |
|
|
|
59.92 |
|
USA Operations |
|
|
28.57 |
|
|
|
61.98 |
|
|
|
55.48 |
|
|
|
67.07 |
|
|
|
65.70 |
|
|
|
65.03 |
|
Total Operations |
|
|
27.33 |
|
|
|
60.35 |
|
|
|
55.83 |
|
|
|
63.20 |
|
|
|
61.54 |
|
|
|
61.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Price ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
32.34 |
|
|
|
33.64 |
|
|
|
30.55 |
|
|
|
29.99 |
|
|
|
29.13 |
|
|
|
43.43 |
|
USA Operations |
|
|
30.12 |
|
|
|
37.20 |
|
|
|
40.79 |
|
|
|
41.96 |
|
|
|
32.91 |
|
|
|
33.75 |
|
Total Operations |
|
|
31.24 |
|
|
|
35.21 |
|
|
|
35.55 |
|
|
|
35.06 |
|
|
|
30.75 |
|
|
|
39.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Netback ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
21.06 |
|
|
|
21.80 |
|
|
|
17.28 |
|
|
|
18.78 |
|
|
|
17.23 |
|
|
|
32.09 |
|
USA Operations |
|
|
14.69 |
|
|
|
22.62 |
|
|
|
25.27 |
|
|
|
27.09 |
|
|
|
18.12 |
|
|
|
20.41 |
|
Total Operations |
|
|
17.91 |
|
|
|
22.15 |
|
|
|
21.18 |
|
|
|
22.30 |
|
|
|
17.61 |
|
|
|
27.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Q1 Report | for the period ended March 31, 2015
Supplemental Oil and Gas Operating Statistics (unaudited)
Results by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Natural Gas Production (MMcf/d) - After Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
717 |
|
|
|
639 |
|
|
|
687 |
|
|
|
644 |
|
|
|
604 |
|
|
|
620 |
|
Duvernay |
|
|
16 |
|
|
|
11 |
|
|
|
12 |
|
|
|
15 |
|
|
|
9 |
|
|
|
8 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (3) |
|
|
111 |
|
|
|
292 |
|
|
|
249 |
|
|
|
291 |
|
|
|
305 |
|
|
|
324 |
|
Bighorn |
|
|
4 |
|
|
|
158 |
|
|
|
(3 |
) |
|
|
162 |
|
|
|
230 |
|
|
|
246 |
|
Deep Panuke |
|
|
182 |
|
|
|
190 |
|
|
|
79 |
|
|
|
186 |
|
|
|
243 |
|
|
|
253 |
|
Other and emerging (1) |
|
|
98 |
|
|
|
88 |
|
|
|
87 |
|
|
|
76 |
|
|
|
72 |
|
|
|
117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canadian Operations |
|
|
1,128 |
|
|
|
1,378 |
|
|
|
1,111 |
|
|
|
1,374 |
|
|
|
1,463 |
|
|
|
1,568 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
36 |
|
|
|
19 |
|
|
|
35 |
|
|
|
35 |
|
|
|
5 |
|
|
|
|
|
Permian |
|
|
34 |
|
|
|
5 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin |
|
|
49 |
|
|
|
43 |
|
|
|
49 |
|
|
|
38 |
|
|
|
43 |
|
|
|
40 |
|
San Juan |
|
|
13 |
|
|
|
8 |
|
|
|
8 |
|
|
|
9 |
|
|
|
7 |
|
|
|
7 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
343 |
|
|
|
402 |
|
|
|
367 |
|
|
|
398 |
|
|
|
407 |
|
|
|
436 |
|
Haynesville |
|
|
230 |
|
|
|
311 |
|
|
|
252 |
|
|
|
298 |
|
|
|
365 |
|
|
|
331 |
|
Jonah |
|
|
|
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
124 |
|
|
|
282 |
|
East Texas |
|
|
|
|
|
|
57 |
|
|
|
|
|
|
|
21 |
|
|
|
97 |
|
|
|
113 |
|
Other and emerging |
|
|
24 |
|
|
|
27 |
|
|
|
19 |
|
|
|
26 |
|
|
|
30 |
|
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total USA Operations |
|
|
729 |
|
|
|
972 |
|
|
|
750 |
|
|
|
825 |
|
|
|
1,078 |
|
|
|
1,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs Production (Mbbls/d) - After Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
23.3 |
|
|
|
18.9 |
|
|
|
24.8 |
|
|
|
20.8 |
|
|
|
13.3 |
|
|
|
16.2 |
|
Duvernay |
|
|
2.8 |
|
|
|
2.1 |
|
|
|
2.5 |
|
|
|
2.6 |
|
|
|
1.8 |
|
|
|
1.4 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (3) |
|
|
1.7 |
|
|
|
8.6 |
|
|
|
2.0 |
|
|
|
9.9 |
|
|
|
11.3 |
|
|
|
11.3 |
|
Bighorn |
|
|
|
|
|
|
7.5 |
|
|
|
(1.5 |
) |
|
|
8.7 |
|
|
|
11.0 |
|
|
|
12.1 |
|
Other and emerging (1) |
|
|
|
|
|
|
0.1 |
|
|
|
0.4 |
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canadian Operations |
|
|
27.8 |
|
|
|
37.2 |
|
|
|
28.2 |
|
|
|
42.3 |
|
|
|
37.4 |
|
|
|
41.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
36.0 |
|
|
|
19.8 |
|
|
|
36.1 |
|
|
|
37.6 |
|
|
|
5.0 |
|
|
|
|
|
Permian |
|
|
26.7 |
|
|
|
3.5 |
|
|
|
13.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin |
|
|
14.3 |
|
|
|
11.6 |
|
|
|
14.0 |
|
|
|
11.8 |
|
|
|
10.1 |
|
|
|
10.5 |
|
San Juan |
|
|
6.7 |
|
|
|
3.9 |
|
|
|
5.6 |
|
|
|
3.5 |
|
|
|
3.9 |
|
|
|
2.7 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
3.7 |
|
|
|
5.0 |
|
|
|
4.3 |
|
|
|
4.8 |
|
|
|
5.3 |
|
|
|
5.4 |
|
Jonah |
|
|
|
|
|
|
1.8 |
|
|
|
|
|
|
|
0.2 |
|
|
|
2.5 |
|
|
|
4.7 |
|
East Texas |
|
|
|
|
|
|
0.5 |
|
|
|
|
|
|
|
|
|
|
|
1.0 |
|
|
|
1.2 |
|
Other and emerging |
|
|
5.5 |
|
|
|
3.5 |
|
|
|
4.4 |
|
|
|
3.8 |
|
|
|
3.0 |
|
|
|
2.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total USA Operations |
|
|
92.9 |
|
|
|
49.6 |
|
|
|
78.2 |
|
|
|
61.7 |
|
|
|
30.8 |
|
|
|
26.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Montney has been realigned to include certain production volumes which were previously reported in Other and emerging. |
(2) |
Other Upstream Operations includes results from plays that are not part of the Companys current strategic focus as well as prospective plays which are under
appraisal, including the TMS which is reported in Other and emerging in the USA Operations. |
(3) |
Wheatland was previously presented as Clearwater. |
|
|
|
|
|
Supplemental Information Prepared in US$ |
Q1 Report | for the period ended March 31, 2015
Supplemental Oil and Gas Operating Statistics (unaudited)
Results by Play (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
Drilling Activity (net wells drilled) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney |
|
|
8 |
|
|
|
79 |
|
|
|
14 |
|
|
|
15 |
|
|
|
23 |
|
|
|
27 |
|
Duvernay |
|
|
6 |
|
|
|
24 |
|
|
|
5 |
|
|
|
7 |
|
|
|
6 |
|
|
|
6 |
|
Other Upstream Operations (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
71 |
|
|
|
174 |
|
|
|
84 |
|
|
|
24 |
|
|
|
|
|
|
|
66 |
|
Bighorn |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Other and emerging |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canadian Operations |
|
|
85 |
|
|
|
279 |
|
|
|
103 |
|
|
|
48 |
|
|
|
29 |
|
|
|
99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
27 |
|
|
|
35 |
|
|
|
21 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
Permian |
|
|
46 |
|
|
|
28 |
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin |
|
|
13 |
|
|
|
64 |
|
|
|
15 |
|
|
|
17 |
|
|
|
14 |
|
|
|
18 |
|
San Juan |
|
|
1 |
|
|
|
43 |
|
|
|
19 |
|
|
|
15 |
|
|
|
5 |
|
|
|
4 |
|
Other Upstream Operations (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Haynesville |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonah |
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
12 |
|
East Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and emerging |
|
|
3 |
|
|
|
15 |
|
|
|
5 |
|
|
|
4 |
|
|
|
4 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total USA Operations |
|
|
90 |
|
|
|
204 |
|
|
|
88 |
|
|
|
50 |
|
|
|
29 |
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Other Upstream Operations includes net wells drilled in plays that are not part of the Companys current strategic focus as well as prospective plays which are under appraisal, including the TMS which is reported
in Other and emerging in the USA Operations. |
(2) |
Wheatland was previously presented as Clearwater. |
|
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Encana Corporation
Further information on Encana
Corporation
is available on the companys website,
www.encana.com, or by
contacting:
INVESTOR CONTACT:
Brian Dutton
Director, Investor Relations 403.645.2285
Patti Posadowski
Sr. Advisor, Investor Relations
403.645.2252
MEDIA CONTACT:
Jay Averill
Director, Media Relations 403.645.4747
GENERAL INQUIRIES
Encana Corporation 500 Centre Street SE PO Box 2850
Calgary, AB , Canada T2P 2S5 Phone:
403.645.2000
Fax: 403.645.3400
encana
Encana (NYSE:ECA)
Historical Stock Chart
From Apr 2024 to May 2024
Encana (NYSE:ECA)
Historical Stock Chart
From May 2023 to May 2024