Management’s Responsibility for Financial Statements · Management’s Responsibility for Financial Statements ... Restructuring and severance costs 1 154,855 18,311 ... LIABILITIES

Management’s Responsibility for Financial Statements

Management is responsible for preparing the consolidated financial statements and the notes hereto. These financial statements

have been prepared in conformity with International Financial Reporting Standards (IFRS) using the best estimates and judgments

of management, where appropriate.

Management is also responsible for maintaining a system of internal controls designed to provide reasonable assurance that assets

are safeguarded and that accounting systems provide timely, accurate, and reliable information.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal

control. The Board is assisted in exercising its responsibilities by the Audit Committee of the Board. At a minimum,

the Committee meets quarterly with management and the internal and external auditors to satisfy itself that management’s

responsibilities are properly carried out and to discuss accounting and auditing matters. The Audit Committee reviews the

consolidated financial statements and recommends approval of the consolidated financial statements to the Board.

The internal and external auditors have full and unrestricted access to the Audit Committee to discuss their audits and their related

findings as to the integrity of the financial reporting process.

“Barry Larson” “Camilo McAllister”

Chief Executive Officer Chief Financial Officer

Toronto, Canada

March 14, 2017.

PACIFIC E&P

Independent Auditors' Report

2

To the Shareholders of

Pacific Exploration & Production Corporation

We have audited the accompanying consolidated financial statements of Pacific Exploration & Production Corporation, which

comprise the consolidated statements of financial position as at December 31, 2016 and 2015 and the consolidated statements

of income (loss), comprehensive income (loss), equity (deficit) and cash flows for the years then ended, and a summary of

significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance

with International Financial Reporting Standards, and for such internal control as management determines is necessary to

enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or

error.

Auditors' responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our

audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical

requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements

are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated

financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of

material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments,

the auditors consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial

statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an

opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting

policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall

presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit

opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Pacific

Exploration & Production Corporation as at December 31, 2016 and 2015 and its financial performance and its cash flows for

the years then ended in accordance with International Financial Reporting Standards.

Toronto, Canada,

March 14, 2017.

PACIFIC E&P

Consolidated Statements of Income (Loss)

[Escriba texto] [Escriba texto]

3

See accompanying notes to the Consolidated Financial Statements.

On behalf of the Board of Directors:

Gabriel de Alba (signed) Raymond Bromark (signed)

Notes 2016 2015

Sales

Oil and gas sales and other income 1,399,120$ 2,688,087$

Trading sales 12,591 136,459

Total sales 5 1,411,711 2,824,546

Cost of operations

Oil & gas operating cost 6 845,885 1,291,242

Purchase of oil for trading 11,515 128,948

(Underlift) overlift (34,864) 35,445

Fees paid on suspended pipeline capacity 7 105,129 123,818

Gross earnings 484,046 1,245,093

Depletion, depreciation and amortization 575,985 1,529,016

General and administrative 144,538 203,153

Impairment and exploration expenses 21 477,005 4,907,209

Share-based compensation 26c (7,775) (1,564)

Restructuring and severance costs 1 154,855 18,311

Loss from operations (860,562) (5,411,032)

Finance costs 22 (191,245) (434,846)

Share of gain of equity-accounted investees 19 62,840 21,537

Equity tax 8 (26,901) (39,149)

Foreign exchange gain (loss) 8,863 (134,477)

(Loss) gain on risk management 28d (139,457) 129,474

Other income (expense) 25,967 (80,992)

Net gain on restructuring 1 3,620,481 -

Net income (loss) before income tax 2,499,986 (5,949,485)

Current income tax expense 9 (42,522) (50,226)

Deferred income tax recovery 9 6,347 516,740

Total income tax (expense) recovery (36,175) 466,514

Net income (loss) for the year 2,463,811$ (5,482,971)$

Attributable to:

Equity holders of the parent 2,448,523 (5,461,859)

Non-controlling interests 15,288 (21,112)

2,463,811$ (5,482,971)$

Basic income (loss) per share attributable to equity holders of the parent 10 48.97 (1,733,923)

Diluted income (loss) per share attributable to equity holders of the parent 10 48.95 (1,733,923)

(In thousands of U.S. dollars, except per share information)

Year ended December 31

PACIFIC E&P

Consolidated Statements of Comprehensive Income (Loss)

4


(In thousands of U.S. dollars) Notes 2016 2015


Other comprehensive income (loss) not to be reclassified to net earnings in subsequent

periods (nil tax effect)

Fair value adjustments 190 (2,435)

Other comprehensive income (loss) to be reclassified to net earnings in subsequent

periods (nil tax effect)

Foreign currency translation 32,981 (150,954)

Unrealized gain on cash flow hedges 28d - 101,336

Unrealized (loss) gain on the time value of cash flow hedges (99) 7,905

Realized gain on cash flow hedges transferred to earnings 28d (12,146) (94,290)

20,926 (138,438)

Total comprehensive income (loss) for the year 2,484,737$ (5,621,409)$

Attributable to:

Equity holders of the parent 2,466,204$ (5,567,437)$

Non-controlling interests 18,533 (53,972)

2,484,737$ (5,621,409)$


PACIFIC E&P

Consolidated Statements of Financial Position

5


As at December 31 As at December 31


ASSETS

Current

Cash and cash equivalents 389,099$ 342,660$

Restricted cash 12 61,036 18,181

Accounts receivables 234,828 517,997

Inventories 13 38,609 27,411

Income tax receivable 59,451 200,813

Prepaid expenses 3,453 5,424

Assets held for sale 14 44,797 -

Risk management assets 28d - 172,783

831,273 1,285,269

Non-current

Oil and gas properties 15 1,191,668 1,818,719

Plant and equipment 17 53,402 118,230

Intangible assets 18 14,800 40,877

Investments in associates 19 415,198 448,266

Other assets 20 182,632 257,019

Restricted cash 12 52,746 17,741

2,741,719$ 3,986,121$

LIABILITIES

Current

Accounts payable and accrued liabilities 28c 576,350$ 1,216,891$

Deferred revenue 11 - 74,795

Risk management liability 28d 31,985 53,066

Income tax payable 10,775 838

Loans and borrowings 22 - 5,377,346

Current portion of obligations under finance lease 23 3,713 13,559

Asset retirement obligation 24 2,834 3,449

625,657 6,739,944

Non-current

Long-term debt 22 250,000 -

Obligations under finance lease 23 19,229 22,952

Deferred tax liability 9 - 6,308

Asset retirement obligation 24 245,798 207,148

1,140,684$ 6,976,352$

EQUITY (DEFICIT)

Common shares 26a 4,745,355$ 2,615,788$

Contributed surplus 123,525 124,150

Other reserves (234,880) (252,561)

Retained deficit (3,138,230) (5,586,753)

Equity (deficit) attributable to equity holders of the parent 1,495,770 (3,099,376)

Non-controlling interests 4 105,265 109,145

Total equity (deficit) 1,601,035$ (2,990,231)$

2,741,719$ 3,986,121$

PACIFIC E&P

Consolidated Statements of Equity (Deficit)

6

For the years ended December 31, 2016 and 2015


(In thousands of U.S. Dollars) Notes Common SharesContributed

Surplus

Retained (Deficit)

EarningsCash flow hedge

Time Value

Reserves

Foreign currency

translation

Fair value

InvestmentTotal

Non-controlling

interests

Total Equity

(Deficit)

As at December 31, 2014 2,610,485$ 129,029$ (124,894)$ 5,100$ (7,806)$ (141,320)$ (2,957)$ 2,467,637$ 187,011$ 2,654,648$

Net loss for the year - - (5,461,859) - - - - (5,461,859) (21,112) (5,482,971)

Other comprehensive income (loss) - - - 7,046 7,905 (118,094) (2,435) (105,578) (32,860) (138,438)

Total comprehensive (loss) income - - (5,461,859) 7,046 7,905 (118,094) (2,435) (5,567,437) (53,972) (5,621,409)

Dividends paid to non-controlling interest 19 - - - - - - - - (26,588) (26,588)

Transaction with non-controlling interest - (4,879) - - - - - (4,879) 2,694 (2,185)

Treasury shares issued as part of severance package 5,303 - - - - - - 5,303 - 5,303

As at December 31, 2015 2,615,788 124,150 (5,586,753) 12,146 99 (259,414) (5,392) (3,099,376) 109,145 (2,990,231)

Net income for the year - - 2,448,523 - - - - 2,448,523 15,288 2,463,811

Other comprehensive income (loss) - - - (12,146) (99) 29,736 190 17,681 3,245 20,926

Total comprehensive income (loss) - - 2,448,523 (12,146) (99) 29,736 190 2,466,204 18,533 2,484,737

Equity and warrant exercise per restructuring transaction 26a 2,129,567 (625) - - - - - 2,128,942 - 2,128,942

Dividends paid to non-controlling interest 19 - - - - - - - - (41,846) (41,846)

Effect of deconsolidation of subsidiary 4 - - - - - - - - 19,433 19,433

As at December 31, 2016 4,745,355$ 123,525$ (3,138,230)$ -$ -$ (229,678)$ (5,202)$ 1,495,770$ 105,265$ 1,601,035$

Attributable to equity holders of parent

PACIFIC E&P

Consolidated Statements of Cash Flows

7



OPERATING ACTIVITIES


Items not affecting cash:

Depletion, depreciation and amortization 575,985 1,529,016

Impairment and exploration expenses 21 477,005 4,883,896

Accretion expense 59,529 160,747

Loss (gain) on risk management 28d 139,457 (129,474)

Share-based compensation 26c (7,775) 3,739

Loss on cash flow hedges included in operating expense 28d - 59,325

Deferred income tax recovery 9 (6,347) (516,740)

Unrealized foreign exchange (gain) loss (10,622) 30,416

Gain on sale of plant and equipment (2,622) -

Share of gain of equity-accounted investees 19 (62,840) (21,537)

Gain on loss of control (15,597) (15,426)

Dividends from associates 19 120,455 56,670

Net gain on restructuring 1 (3,620,481) -

Other (7,841) 20,839

Deferred revenue (non- cash settlement) proceeds 11 (75,000) 74,155

Changes in non-cash working capital 29 (144,347) (432,575)

Net cash (used) provided by operating activities (117,230)$ 220,080$

INVESTING ACTIVITIES

Additions to oil and gas properties and plant and equipment (136,528) (554,164)

Additions to exploration and evaluation assets (26,092) (94,621)

Investment in associates and other assets (9,412) (69,703)

Net proceeds from sale of other plant and equipment 2,350 -

Increase in restricted cash and others (74,775) (33,594)

Finance loan repayment from Bicentenario - 41,992

Net cash inflow on loss on control - 5,489

Net cash used in investing activities (244,457)$ (704,601)$

FINANCING ACTIVITIES

Payment of debt and leases (37,838) (573,045)

Transaction costs - (5,475)

Drawdown of revolving credit facility - 1,000,000

Restructuring Transaction 1 480,000 -

Advances from short-term debt - 125,000

Dividends paid to non-controlling interest 19 (41,846) (26,588)

Proceeds on option exercise - 15

Net cash provided by financing activities 400,316$ 519,907$

Effect of exchange rate changes on cash and cash equivalents 7,810 (26,480)

Change in cash and cash equivalents during the year 46,439 8,906

Cash and cash equivalents, beginning of the year 342,660 333,754

Cash and cash equivalents, end of the year 389,099$ 342,660$

Cash 360,530$ 254,479$

Cash equivalents 28,569 88,181

389,099$ 342,660$


PACIFIC E&P

Notes to the Consolidated Financial Statements (U.S.$ thousands, except share and per share amounts or unless otherwise stated)

8

1. Corporate Information

Pacific Exploration & Production Corporation (the “Company”) is an oil and gas company incorporated and domiciled in Canada

that is engaged in the exploration, development, and production of crude oil and natural gas primarily in Colombia and Peru.

Prior to April 19, 2016, the Company’s common shares were listed and publicly traded on the Toronto Stock Exchange (“TSX”)

and Bolsa de Valores de Colombia (the “Colombian Stock Exchange”). As a result of the Company entering into the

comprehensive Restructuring Transaction (explained below), the Company’s common shares were delisted from the TSX and

suspended from trading on the Colombian Stock Exchange. On November 3, 2016, upon completion of the Restructuring

Transaction, the newly issued common shares were relisted on the TSX only under the symbol “PEN.” The Company was

officially delisted from the Colombian Stock Exchange on November 3, 2016. The Company’s registered office is located at

Suite 650 – 1188 West Georgia Street, Vancouver, British Columbia, V6E 4A2, Canada, and it also has corporate offices in

Toronto, Canada and Bogota, Colombia.

These consolidated financial statements of the Company, which are comprised of the Company as the parent and all its

subsidiaries, were authorized for issuance by the Board of Directors on March 14, 2017.

Comprehensive Restructuring Transaction

On April 19, 2016, the Company with the support of certain holders of its senior unsecured notes and lenders under its credit

facilities, entered into an agreement with The Catalyst Capital Group Inc. (“Catalyst”) with respect to a comprehensive financial

restructuring (“Restructuring Transaction”). Under the terms of the agreement, the claims of the senior noteholders, the lenders

under the credit facilities, and certain other third parties (together, the “Affected Creditors”) were exchanged for new common

shares of the reorganized company. In addition, Catalyst and certain Affected Creditors provided new cash financing to

recapitalize the Company.

On April 27, 2016, the Company, including certain of its direct and indirect subsidiaries, obtained an Initial Order from the

Superior Court of Justice in Ontario under the Companies’ Creditors Arrangement Act (“CCAA”) with respect to the

Restructuring Transaction.

On November 2, 2016, the Company successfully completed the Restructuring Transaction upon approval of the CCAA plan of

arrangement by the Superior Court of Justice in Ontario and through appropriate proceedings in Colombia and in the United

States. The Restructuring Transaction included the following key features:

• The operations of the Company continued as normal throughout the period of restructuring and obligations to the

Company’s suppliers, trade partners and contractors continued to be met.

• Certain of the Company’s Affected Creditors (the “Funding Creditors”) and Catalyst jointly provided $500 million of

debtor-in-possession financing (“DIP Financing”) less an original issue discount of 4%. The DIP Financing was secured

by assets of the Company and its subsidiaries (Note 22). Pursuant to the DIP Financing, Catalyst provided $240 million

cash (after taking into account the original issue discount) for the purchase of notes (the “Plan Sponsor DIP Notes”)

and the Funding Creditors provided the other $240 million cash for the purchase of notes (the “Creditor DIP Notes”)

and warrants with a nominal exercise price (the “Warrants”).

• Upon implementation of the Restructuring Transaction, claims by the Affected Creditors in the amount of approximately

$5.7 billion (including principal and accrued interest) were exchanged for approximately 58.2% of the common shares

of the reorganized company.

• The Affected Creditors also had the opportunity to receive cash in lieu of some or all of the common shares of the

reorganized Company that they would otherwise be entitled to receive (the “Cash Elections”). Approximately 1.5% of

the common shares of the reorganized company were acquired by Catalyst as Plan Sponsor, and another 0.35% acquired

by certain of the Company’s Affected Creditors through subscriptions to fund the Cash Elections.

PACIFIC E&P


9

• Upon implementation of the Restructuring Transaction, the Plan Sponsor DIP Notes were exchanged for 29.3% of the

total newly issued common shares. Catalyst as Plan Sponsor acquired an additional 1.5% of the common shares through

the Cash Elections for a total interest of 30.8% of the common shares of the reorganized company.

• Upon implementation, the Creditor DIP Notes were amended and restated as five-year secured notes (the “Exit Notes”).

The Exit Notes will accrue interest at a rate equal to 10%. The Funding Creditors also exercised the Warrants in

exchange for 12.5% of the newly issued common shares.

• Upon implementation, all the previously issued and outstanding common shares of the Company, together with the

common shares issued as part of the Restructuring Transaction, were consolidated on the basis of 100,000 pre-

consolidation shares to one post-consolidation share. As a result, upon completion of the Restructuring Transaction

there were 50,002,363 common shares issued and outstanding in the reorganized Company, allocated as follows:

(1) Includes shares Catalyst received through subscriptions to fund the Cash Elections.

• The Company’s common shares that were issued and outstanding prior to the implementation of the Restructuring

Transaction were extensively diluted as a result of the 100,000-to-1 consolidation.

The Restructuring Transaction substantially changed the capital structure of the Company, as set out below:

(1) Refer to Note 22 for details on the credit facilities, senior unsecured notes, and DIP Notes.

DIP Cash Collateral Account

On June 22, 2016, in accordance with the Restructuring Transaction, the funds related to the DIP Financing were deposited into

a Canadian bank account in the name of the Company and were subject to a number of conditions, including the following;

• The Company was to maintain at all times prior to the completion of Restructuring Transaction a minimum unrestricted

operating cash balance of $200 million;

• All unrestricted operating cash in excess of $100 million remaining in the Company’s cash accounts excluding that

which was in the DIP Cash Collateral Account at the end of each week was to be deposited into the DIP Cash Collateral

account; and

• If at the end of each week the unrestricted operating cash balance in the Company’s cash accounts excluding that which

was in the DIP Cash Collateral account was below $100 million, a withdrawal would be made from the DIP Cash

Collateral Account in the amount required to return the balance to $100 million.

Upon completion of the Restructuring Transaction on November 2, 2016, the conditions associated with the DIP Cash Collateral

Account were removed and the remaining cash balance was transferred back to the Company’s operating accounts.

Shareholder Percentage

Catalyst (1) 30.8

Affected Creditors 69.2

December 31, 2016

Immediately before

restructuring

Credit facilities(1) -$ 1,215,440$

Senior unsecured notes(1) - 4,104,200

Catalyst & Creditor DIP Notes(1) - 500,000

Secured Senior Notes (Exit Notes, due 2021) 250,000 -

Total loans and borrowings 250,000$ 5,819,640$

Number of common shares outstanding 50,002,363 315,021,198

Principal outstanding as at

PACIFIC E&P


10

Colombian Affected Creditors Security

On June 10, 2016, the Superintendencia de Sociedades of Colombia (the “Superintendencia”) granted an order under Ley 1116

recognizing the CCAA proceedings as the foreign main proceedings for the Restructuring Transaction. The Superintendencia

also authorized the granting of security over the Colombian branches in connection with the DIP Financing and resolved that $50

million should be held in trust until the Restructuring Transaction was complete as security for the Colombian Affected Creditors

(“Colombian Affected Creditors Security”).

Upon completion of the Restructuring Transaction on November 2, 2016, the Colombian Affected Creditors Security was

released. Consequently, the $50 million held in trust on behalf of Colombian creditors was returned to the Company, which in

turn established a $39 million trust account in favour of Colombian trade creditors that had not yet been paid. The purpose of this

Colombian trust account is to secure the amounts owed to the mentioned creditors and to administer and execute payments, as

set out in the payment schedule previously submitted to the Superintendencia. The balance in this trust account as at December

31, 2016 was $28 million and recorded as current restricted cash (Note 12). The security and restriction over the trust account

were subsequently lifted on March 13, 2017, and the Company has initiated the processes to have the remaining balance in the

trust account released (Note 30).

Net Gain on Completion of Restructuring Transaction

Upon completion of the Restructuring Transaction, the claims of the Affected Creditors and the Plan Sponsor DIP Notes were

extinguished, and the Warrants held by the Funding Creditors were exercised, in exchange for newly issued shares of the

Company. The net difference between i) the carrying amounts of the claims of the Affected Creditors, the Plan Sponsor DIP

Notes, and the Warrants, and ii) the fair value of the common shares issued, was recorded as a gain.

The estimated fair value of the common shares issued to the Affected Creditors, Catalyst and Warrant holders was estimated

using the closing share price of $42.5 (C$57) per share on November 3, 2016, which was the day that the Company’s common

shares resumed trading on the TSX.

Restructuring and Severance Costs

During the year ended December 31, 2016, the Company incurred $154.9 million (2015: $18.3 million) in costs related to the

Restructuring Transaction and severances for work force reductions. Included in restructuring costs were retention bonuses for

certain employees of the Company as part of the CCAA Initial Order.

Immediately before

restructuring

Fair value of

Common Shares

Consolidated

Statement of Income

(Loss) impact

Claims of Affected Creditors 5,498,476$ 1,237,836$ 4,260,640$

Plan Sponsor DIP Notes 250,000 624,301 (374,301)

Warrants - 265,858 (265,858)

5,748,476$ 2,127,995$ 3,620,481$

2016 2015

Restructuring cost 121,608$ -$

Severance 33,247 18,311

Total 154,855$ 18,311$


PACIFIC E&P


11

2. Basis of Preparation and Significant Accounting Policies

The consolidated financial statements of the Company have been prepared in accordance with International Financial Reporting

Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The consolidated financial statements

have been prepared on a historical cost basis except for derivative financial instruments and available-for-sale investments that

have been measured at fair value. The consolidated financial statements are presented in U.S. dollars and all values are rounded

to the nearest thousand, except where otherwise indicated.

Basis of Consolidation

The results of the investees that the Company controls are consolidated in these financial statements. The Company controls an

investee if, and only if, the Company has all of the following:

• Power over the investee (i.e., existing rights that give it the current ability to direct the relevant activities of the investee);

• Exposure, or rights, to variable returns from its involvement with the investee; and

• The ability to use its power over the investee to affect its returns.

Where the Company has less than a majority of the voting or similar rights of an investee, it considers all relevant facts and

circumstances in assessing whether it has power over an investee, including:

• The contractual arrangements with the other vote holders of the investee;

• Rights arising from other contractual arrangements; and

• The Company’s voting rights and potential voting rights.

The Company reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one

or more of the three elements of control. Consolidation of a subsidiary begins when the Company obtains control over the

subsidiary and ceases when the Company loses control of the subsidiary. Assets, liabilities, income and expenses of a subsidiary

acquired or disposed of during the year are included in the Consolidated Statements of Income (Loss) from the date the Company

gains control until the date the Company ceases to control the subsidiary.

Net earnings and each component of Other Comprehensive Income (“OCI”) are attributed to the equity holders of the parent and

to the Non-Controlling Interests (“NCI”) even if this results in the NCI having a deficit balance. When necessary, adjustments

are made to the financial statements of subsidiaries to bring their accounting policies in line with the Company’s accounting

policies. All intragroup assets and liabilities, equity, income, expenses and cash flows relating to transactions between members

of the Company are eliminated in full upon consolidation.

A change in the ownership interest of a subsidiary without a loss of control is accounted for as an equity transaction. If the

Company loses control over a subsidiary, it:

• Derecognizes the assets (including goodwill) and liabilities of the subsidiary;

• Derecognizes the carrying amount of any NCI;

• Derecognizes the cumulative translation differences recorded in equity;

• Recognizes the fair value of the consideration received;

• Recognizes the fair value of any investment retained;

• Recognizes any surplus or deficit in the statements of income and comprehensive income; and

• Reclassifies the parent’s share of components previously recognised in OCI to net earnings as appropriate and as would

be required if the Company had directly disposed of the related assets or liabilities.

2.1. Significant Accounting Judgments, Estimates and Assumptions

The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the

reported amounts of assets, liabilities and contingent liabilities at the date of the consolidated financial statements and reported

PACIFIC E&P


12

amounts of revenues and expenses during the reporting period. Estimates and judgments are continuously evaluated and are based

on management’s experience and other factors, including expectations of future events that are believed to be reasonable under

the circumstances. However, actual outcomes can differ from these estimates.

Critical Judgments in Applying Accounting Policies

The following critical judgments have been made by the Company in applying accounting policies that have the most significant

impact on the amounts recognized in the consolidated financial statements.

Plan Sponsor and Creditor DIP Notes

The $500 million DIP Notes were issued on June 22, 2016. These DIP Notes include various features including conversion into

new common shares, exchanges for a new set of notes, and additional equity purchase warrants exercisable for new common

shares (Note 22). The Company was required to assess whether the various features including the warrants and the conversion

feature were to be recognized as a financial liability under IFRS 9 (2013) or as equity in accordance with IAS 32. The Company

was required to apply judgment to determine whether the concept of “fixed for fixed” criterion was applicable in concluding the

classification of the conversion feature and the warrants. In applying this concept, the Company determined that the warrants

and the conversion feature were financial liabilities with no value as of the issuance date.

Lot 192 agreement

The Company has entered into an agreement with the Peruvian state oil and gas company Perupetro S.A. to provide extraction

services in exchange for volumes of crude oil produced as determined in accordance with the agreement. The Company is required

to apply significant judgments in relation to how it accounts for this agreement and in particular, the point of revenue recognition.

In determining when to recognize the revenue, the Company has analyzed the timing of the transfer of legal rights and when the

value can be reasonably calculated. Based on this analysis, the Company has accounted for the Lot 192 agreement as a production-

sharing arrangement whereby revenue is recognized at the point where the Company’s share of the crude oil is sold to third parties

and such sale price is used to measure the revenue.

Dilution agreement

The Company has entered into a dilution service agreement with an unrelated third party whereby the third party’s natural gasoline

or similarly light products would be mixed with the Company’s heavy crude oil and transported through pipelines in Colombia.

The Company pays a fixed fee per barrel of diluent provided by the third party. The Company is required to apply significant

judgment regarding how it accounts for this transaction and in particular the point of revenue recognition. In determining the

revenue recognition point, the Company has analyzed whether the legal rights of the product are transferred. Based on this

analysis, the Company has concluded it holds a legal right to its share of the blended product per the terms of the contract at the

dilution point and revenue related to the blended product is recognized by the Company upon sale to the ultimate customers.

Cash-generating units

The determination of cash-generating units (“CGUs”) requires the Company to apply judgments, and the CGUs may change over

time to reflect changes in the Company’s oil and gas assets. CGUs have been identified to be the major areas within which there

exist groups of producing blocks that share similar characteristics, infrastructure, and cash inflows that are largely independent

of cash inflows of other groups of assets. Impairment assessment is generally carried out separately for each CGU based on cash

flow forecasts calculated using oil & gas reserves and resources for each CGU.

Functional currency

The determination of the Company's functional currency requires analyzing facts that are considered primary factors, and if the

result is not conclusive, secondary factors. The analysis requires the Company to apply significant judgment since primary and

secondary factors may be mixed. In determining its functional currency, the Company analyzed both primary and secondary

PACIFIC E&P


13

factors including the currency of the Company's revenues, operating costs in the countries in which it operates, and sources of

debt and equity financing.

Contingencies

By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of

contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. Refer to

Note 25.

Exploration and evaluation

Exploration and Evaluation (“E&E”) assets are tested for impairment (Note 21) when indicators of impairment are present and

when E&E assets are transferred to oil and gas properties. This test is performed at the CGU level and not at the individual

property level. E&E assets are allocated to CGUs on the basis of several factors, including, but not limited to, proximity to

existing CGUs, ability to share infrastructure and workforce, and management’s grouping of these assets for decision-making

and budget allocations. If the E&E property is not part of a particular existing operational CGU, it is assessed on the basis of a

geographically similar pool of E&E assets. In assessing impairment for E&E assets, the Company is required to apply judgment

in considering various factors that determine technical feasibility and commercial viability.

Estimation Uncertainty and Assumptions

Oil and gas properties

Oil and gas properties are depreciated using the unit-of-production method. During 2016, in applying the unit-of-production

method, oil and gas properties were depleted over proved reserves, compared to 2015, when they were depleted over proved and

probable. The calculation of the unit-of-production rate of amortization could be impacted to the extent that actual production in

the future is different from current forecasted production based on proved reserves. This would generally result from significant

changes in any of the following:

• Changes in reserves;

• The effect on reserves of differences between actual commodity prices and commodity price assumptions; and/or

• Unforeseen operational issues.

Termination of the Rubiales and Piriri Contracts

On June 30, 2016, the joint operating agreements for the Rubiales and Piriri fields expired, the fields were returned to Ecopetrol

S.A. (“Ecopetrol”), and all associated contracts were terminated. In accordance with the termination rules contained in the

agreements, Ecopetrol assumed direct operations and retained 100% of the rights over the fields. In prior years, in anticipation of

the relinquishment of the fields, the Company has been recording a provision for its termination obligation. As a result of the

termination of the contracts, the Company has recorded an additional $9.4 million in obligations relating to the relinquishment

of the fields. The additional obligations relate mainly to the Company’s share of environmental commitments, abandonment

costs, and other operating activities. The Company has determined that this additional obligation represents a change in estimate

resulting from new information obtained during the year. The Company has identified various contingent liabilities and has

determined that it is not probable that an outflow of resources will be required to settle these potential liabilities. In order to

recognize these obligations, certain assumptions were used such as the expected timing of expenses and future supplier and

contractor charges. Such assumptions could be impacted by the following outcomes:

• Changes in foreign exchange rates;

• Changes in the timing of future activities or cash flows; and/or

• Unforeseen political or legislative changes.

PACIFIC E&P


14

Recoverable amounts

The recoverable amounts of CGUs and individual assets have been determined based on the higher of value-in-use calculations

and fair values less costs to sell. These calculations require the use of estimates and assumptions. Estimates include but are not

limited to estimates of the discounted future after-tax cash flows expected to be derived from the Company’s oil and gas properties

and the discount rate. Changes in oil price forecasts, reserves, and estimated future costs of production, future capital costs,

decommissioning costs, and income taxes can result in changes in the recoverable amount of the CGUs. It is reasonably possible

that the oil price assumption may change, which may then impact the estimated life of the field and require a material adjustment

to the carrying value of goodwill, tangible assets and exploration and evaluation assets. The Company monitors internal and

external indicators of impairment relating to its tangible and intangible assets. Refer to Note 21.

Association contracts

Certain association contracts in Colombia provide for an adjustment to the partner’s share when certain volume and price

thresholds are reached. As a result, from time to time the Company may be required to estimate the impact of such contracts and

make the appropriate accrual.

Decommissioning costs

Decommissioning costs will be incurred by the Company at the end of the operating life of certain facilities and properties. The

ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to

relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected

timing and amount of expenditure can also change: for example, in response to changes in reserves or changes in laws and

regulations or their interpretation. As a result, there could be significant adjustments to the asset retirement obligation established,

which would affect future financial results. Refer to Note 24.

Fair value measurement

The fair values of financial instruments are estimated based on market and third-party inputs. These estimates are subject to

changes in the underlying commodity prices, interest rates, foreign exchange rates, and non-performance risk.

2.2. Summary of Significant Accounting Policies

Interests in Joint Arrangements

IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is defined

as contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being

those that significantly affect the returns of the arrangements) require unanimous consent of the parties sharing control.

Joint operations

A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the

assets and obligations for the liabilities relating to the arrangement.

In relation to its interest in joint operations, the Company recognizes its:

• Assets, including its share of any assets held jointly;

• Liabilities, including its share of any liabilities incurred jointly;

• Revenue from the sale of its share of the output arising from joint operation; and

• Expenses, including its share of any expenses incurred jointly.

PACIFIC E&P


15

Joint ventures

A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net

assets of the joint arrangement. The Company’s investments in its joint ventures are accounted for using the equity method.

Under the equity method, the investment in the joint venture is initially realized at cost and the carrying value is adjusted thereafter

to include the Company’s pro rata share of post-acquisition earnings of the joint venture, computed using the consolidation

method. The amount of the adjustment is included in the determination of net earnings and the carrying amount of the investment

is also increased or decreased to reflect the Company’s share of capital transactions. Profit distributions received or receivable

from a joint venture reduce the carrying value of the investment. Goodwill relating to the joint venture is included in the carrying

amount of the investment and is neither amortized nor individually tested for impairment.

At each reporting date, the Company determines whether there is objective evidence that the investment in the joint venture is

impaired. If there is such evidence, the Company calculates the amount of impairment as the difference between the recoverable

amount of the joint venture and its carrying value, then recognizes the loss in the consolidated statement of income.

Reimbursement of the joint arrangement operator’s costs

When the Company is the operator of a joint arrangement and receives reimbursement of direct costs charged to the joint

arrangement, such charges represent reimbursements of costs that the operator incurred as an agent for the joint arrangement and

therefore have no effect on the consolidated statement of income.

In many cases, the Company also incurs certain general overhead expenses in carrying out activities on behalf of the joint

arrangement. As these costs can often not be specifically identified, joint arrangement agreements allow the operator to recover

the general overhead expenses incurred by charging an overhead fee that is based on a fixed percentage of the total costs incurred

for the year. Although the purpose of this re-charge is very similar to the reimbursement of direct costs, the Company is not acting

as an agent in this case. Therefore, the general overhead expenses and the overhead fee are recognized in the consolidated

statement of income as lower expenses.

Business Combinations and Goodwill

On the acquisition of a subsidiary, the acquisition method of accounting is used whereby the purchase consideration transferred

and any contingent consideration is allocated to the identifiable assets, liabilities and contingent liabilities (identifiable net assets)

on the basis of fair value at the date of acquisition. Those petroleum reserves and resources that are able to be reliably valued are

recognized in the assessment of fair value upon acquisition. Other potential reserves, resources and rights, for which fair values

cannot be reliably determined, are not recognized.

Goodwill is initially measured at cost being the excess of the purchase consideration of the business combination over the

Company’s share in the net fair value of the acquirer’s identifiable assets, liabilities and contingent liabilities.

If the fair value attributable to the Company’s share of the identifiable net assets exceeds the fair value of the consideration, the

Company reassesses whether it has correctly identified and measured the assets acquired and liabilities assumed and recognizes

any additional assets or liabilities that are identified in that review. If an excess remains after reassessment, the Company

recognizes the resulting gain in net income on the acquisition date.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment

testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Company’s CGUs or

groups of CGUs that are expected to benefit from the synergies of the combination, irrespective of whether other assets or

liabilities of the acquiree are assigned to those units. Goodwill is tested at the level monitored by management which is the

operating segment level.

PACIFIC E&P


16

Non-controlling interest

Where the ownership of a subsidiary is less than 100%, an NCI exists and is accounted for and reported in equity. For each

business combination, the Company elects whether to measure the NCI in the acquiree at fair value or at the proportionate share

of the acquiree’s net assets.

Net earnings and changes in ownership interests in a subsidiary attributable to NCI are identified and disclosed separately to that

of the Company.

If the Company loses control over a subsidiary with NCI, it derecognizes the carrying amount of the NCI.

Cash and Cash Equivalents

Cash and cash equivalents in the consolidated statement of financial position comprise cash, short-term cashable securities in

order to pay taxes within Colombia (“TIDIS”) at banks and at hand and short-term deposits with an original maturity of three

months or less.

For the purpose of the consolidated statement of cash flows, cash and cash equivalents consist of cash and cash equivalents as

defined above, net of outstanding bank overdrafts.

Inventories

Oil and gas inventory and operating supplies are valued at the lower of average cost and net realizable value. Cost is determined

on a weighted average basis. Cost consists of material, labour, and direct overhead. Previous impairment write-downs are reversed

when there is a recovery of the previously impaired inventory. Costs of diluents are included in production and operating costs.

Non-current assets held for sale

The Company classifies non-current assets and disposal groups as held for sale if their carrying amounts will be recovered

principally through a sale rather than through continuing use. Such non-current assets classified as held for sale are measured at

the lower of their carrying amount and fair value less costs of disposal.

The criteria for held for sale classification is regarded as met only when the sale is highly probable and the asset is available for

immediate sale in its present condition. Actions required to complete the sale should indicate that it is unlikely that significant

changes to the sale will be made or that the decision to sale will be withdrawn. The Company must be committed to the sale

expected within one year from the date of the classification.

Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale.

Oil and Gas Properties, Exploration and Evaluation Assets, and Plant and Equipment

Oil and gas properties and plant and equipment

Oil and gas properties and plant and equipment are stated at cost, less accumulated depletion and depreciation and accumulated

impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any cost directly attributable to

bringing the asset into operation, the ongoing estimate of the asset retirement obligation, and for qualifying assets, borrowing

costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to

acquire the asset. The capitalized value of a finance lease is also included within plant and equipment.

Depletion, depreciation and amortization

Oil and gas properties are depleted using the unit-of-production method. In applying the unit-of-production method, oil and gas

properties are depleted over an appropriate reserve base that is reviewed and assessed periodically. The depletion base includes

PACIFIC E&P


17

proved reserves (2015: proved and probable reserves). The unit-of-production rate for the depletion of field development costs

takes into account expenditures incurred to date together with approved future development expenditures required to develop

reserves.

Plant and equipment are generally depreciated on a straight-line basis over their estimated useful lives, which range from one to

ten years. Major inspection costs are amortized over three to five years, which represents the estimated period before the next

planned major inspection. Plant and equipment held under finance leases are depreciated over the shorter of lease term and

estimated useful life.

Development costs

Expenditure on the construction, installation or completion of infrastructure facilities such as pipelines and the drilling of

development wells, including unsuccessful development or delineation wells, is capitalized in oil and gas properties.

Exploration and evaluation costs

All licence acquisition, exploration and appraisal costs of technical services and studies, seismic acquisition, exploratory drilling

and testing are initially capitalized by well, field, unit of account or specific exploration unit as appropriate. Expenditures incurred

during the various exploration and appraisal phases are carried forward until the existence of commercial reserves and the

technical feasibility and commercial viability are demonstrable and approved by the appropriate regulator. If commercial reserves

have been discovered and technical feasibility and commercial viability are demonstrable, the carrying value of the exploration

and evaluation assets, after any impairment loss, is reclassified as an oil and gas property. If technical feasibility and commercial

viability cannot be demonstrated upon completion of the exploration phase, the carrying value of the exploration and evaluation

costs incurred is expensed in the period this determination is made.

Exploration and evaluation assets are tested for impairment when indicators of impairment are present and when exploration and

evaluation assets are transferred to oil and gas properties.

Pre-licence costs

Costs incurred prior to having obtained the legal rights to explore an area are expensed to the consolidated statement of income

as they are incurred.

Major maintenance and repairs

Expenditures on major maintenance refits or repairs comprise the cost of replacement assets or parts of assets, inspection costs

and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is

probable that future economic benefits associated with the item will flow to the Company, the expenditure is capitalized. Where

part of the asset was not separately considered as a component, the replacement value is used to estimate the carrying amount of

the replaced assets and is immediately written off. Inspection costs associated with major maintenance programs are capitalized

and amortized over the period to the next inspection. All other maintenance costs are expensed as incurred.

Carried interest and farm-in arrangements

The Company recognizes its expenditures under a farm-in or carried interest arrangement with respect to its interest and the

interest retained by the other party as and when the costs are incurred. Such expenditures are recognized in the same way as the

Company’s directly incurred expenditures.

Intangible Assets

Intangible assets are stated as the amount initially paid less accumulated amortization and accumulated impairment losses.

Following initial recognition, the intangible asset is amortized based on usage or the straight-line method over the term of the

agreement. The Company does not have any intangible assets with an indefinite life that would be not subject to amortization.

PACIFIC E&P


18

Internally generated intangible assets not meeting the capitalization criteria are not capitalized and the expenditure is reflected in

the consolidated statement of income in the period in which the expenditure is incurred.

Investments in Associates

When the Company determines that it has significant influence over an investment, the investment is accounted for using the

equity method. Under the equity method, the investment is initially recorded at cost and the carrying value is adjusted thereafter

to include the Company’s pro rata share of post-acquisition earnings of the investee and computed using the consolidation method.

The amount of the adjustment is included in the determination of net earnings and the investment account is also increased or

decreased to reflect the Company’s share of capital transactions. Profit distributions received or receivable from an investee

reduce the carrying value of the investment.

The Company periodically assesses its investments to determine whether there is any indication of impairment. When there is

an indication of impairment, the Company tests the carrying amount of the investment to ensure it does not exceed the higher of

the present value of cash flows expected to be generated (value-in-use) and the amount that could be realized by selling the

investment (fair value less cost of disposal). When a reduction to the carrying amount of an investment is required after applying

the impairment test, an impairment loss is recognized equal to the amount of the reduction.

Impairment of Assets

The Company assesses at each reporting date whether there is an indication that an asset may be impaired. If any indication exists,

or when annual impairment testing for an asset is required, the Company estimates the asset’s recoverable amount. An asset’s

recoverable amount is the higher of an asset’s or CGU’s fair value less costs of disposal and its value-in-use. Individual assets

are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that are largely

independent of the cash flows of other groups of assets. Where the carrying amount of an asset or CGU exceeds its recoverable

amount, the asset is considered impaired and is written down to its recoverable amount. In assessing value-in-use, the estimated

future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of

the time value of money and the risks specific to the asset. Fair value less costs of disposal is estimated based on comparable

market transactions, if available.

The Company bases its impairment calculation on detailed budgets and forecast calculations, which are prepared separately for

each of the Company’s CGUs to which the individual assets are allocated. These budgets and forecast calculations generally

cover the entire period of life of the asset.

For assets excluding goodwill, an assessment is made at each reporting date as to whether there is any indication that previously

recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Company estimates the

asset’s or CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the

assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is

limited so that the carrying amount of the asset does not exceed its recoverable amount nor exceed the carrying amount that would

have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is

recognized in the consolidated statement of income.

Goodwill is tested for impairment annually (as at December 31) and when circumstances indicate that the carrying value may be

impaired. Impairment is determined by assessing the recoverable amount of each CGU (or group of CGUs) to which the goodwill

relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognized. Impairment

losses relating to goodwill cannot be reversed in future periods.

Financial Instruments

Financial assets and financial liabilities are recognized when the Company becomes a party to the contractual provisions of the

instrument.

PACIFIC E&P


19

Financial assets and financial liabilities are initially measured at fair value. Transaction costs that are directly attributable to the

acquisition or issue of financial instruments classified as amortized cost are included with the carrying value of such instruments.

Transaction costs directly attributable to the acquisition of financial instruments classified as fair value through profit or loss are

recognized immediately in earnings.

Financial Assets

All recognized financial assets are subsequently measured in their entirety at either amortized cost or fair value depending on its

classification.

Financial assets that meet the following conditions are subsequently measured at amortized cost less impairment loss:

• The asset is held within a business model whose objective is to hold assets in order to collect contractual cash flows;

• The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal

and interest on the principal amount outstanding; and

• The asset was not acquired principally for the purpose of selling in the near term or management for short-term profit

taking (held for trading).

All other financial assets except equity investments as described below are subsequently measured at fair value and classified as

fair value through profit and loss (“FVTPL”). The gains or losses arising on remeasurement are recognized in earnings and

included in the other expenses line in the Consolidated Statements of Income (Loss).

On the day of acquisition of an equity instrument, the Company can make an irrevocable election (on an instrument-by-instrument

basis) to designate investments in equity instruments as at fair value through other comprehensive income (“FVTOCI”).

Designation at FVTOCI is not permitted if the equity investment is held for trading. Investments in equity instruments at FVTOCI

are initially measured at fair value plus transaction costs. Subsequently they are measured at fair value with gains and losses

arising from changes in fair value recognized in other comprehensive income and accumulated in the fair value instrument. The

cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments. The Company has designated all

investments in equity instruments as FVTOCI on initial application of IFRS 9 (2013) (see Note 28).

Financial Liabilities

Financial liabilities are classified as FVTPL when the financial liability is either held for trading or is designated as FVTPL.

Financial liabilities at FVTPL are stated at fair value. Any gains or losses arising on remeasurement of held-for-trading financial

liabilities are recognized in earnings. Such gains or losses recognized in profit or loss incorporate any interest paid on the financial

liabilities.

Financial liabilities that are not held for trading and are not designated as FVTPL are measured at amortized cost at the end of

subsequent accounting periods. The carrying amounts of financial liabilities that are subsequently measured at amortized cost are

determined based on the effective interest method. The effective interest method is a method of calculating the amortized cost of

a financial liability and allocating interest expense over the expected life of the financial liability.

Fair value hierarchy

The Company uses a three-level hierarchy to categorize the significance of the inputs used in measuring or disclosing the fair

value of financial instruments. The three levels of the fair value hierarchy are:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities. Active markets are those in which

transactions occur in a frequency and volume sufficient to provide pricing information on an ongoing basis.

PACIFIC E&P


20

Level 2 – Inputs other than quoted prices that are observable for the asset or liability either directly or indirectly. Level 2 valuations

are based on inputs, including quoted forward prices for commodities, time value, volatility factors and broker quotations that

can be substantially observed or corroborated in the marketplace.

Level 3 – Valuations in this level are those with inputs that are less observable, unavailable or where the observable data does

not support the majority of the instrument’s fair value. Level 3 instruments may include items based on pricing services or broker

quotes where the Company is unable to verify the observability of inputs into their prices. Level 3 instruments include longer-

term transactions, transactions in less active markets or transactions at locations for which pricing information is not available.

In these instances, internally developed methodologies are used to determine fair value, which primarily includes extrapolation

of observable future prices to similar locations, similar instruments or later time periods.

If different levels of input are used to measure a financial instrument’s fair value, the classification within the hierarchy is based

on the lowest-level input that is significant to the fair value measurement.

Derivative Financial Instruments

The Company enters into a variety of derivative financial instruments to manage its exposure to foreign exchange rate risks and

commodity price risks, including collars and forwards.

Derivatives are initially recognized at fair value at the date the derivative contracts are entered into and are subsequently

remeasured to their fair value at the end of each reporting period. The resulting gain or loss is immediately recognized in earnings

unless the derivative is designated and effective as a hedging instrument (further explained below under Hedge Accounting), in

which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

Embedded Derivatives

Derivatives embedded in non-derivative host contracts that are not financial assets within the scope of IFRS 9 (2013) (e.g.

financial liabilities) are treated as separate derivatives when their risks and characteristics are not closely related to those of the

host contracts and the host contracts are not measured at FVTPL. Fair value is determined in the manner described in Note 28.

Hedge Accounting

The Company may from time to time designate certain hedging instruments, with respect to foreign currency risk and commodity

price risk, as cash flow hedges.

At the inception of the hedge relationship, the Company documents the relationship between the hedging instrument and the

hedged item along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore,

at the inception of the hedge and on an ongoing basis, the Company documents whether the hedging instrument is highly effective

in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk.

Cash Flow Hedges

The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized

in other comprehensive income and accumulated under the heading of cash flow hedge reserve. The gain or loss relating to the

ineffective portion is recognized immediately in profit or loss and is included in the foreign exchange gain or loss line item of the

statements of income for foreign currency hedging instruments and the risk management gain or loss line item for commodity

hedging instruments.

Amounts previously recognized in other comprehensive income and accumulated in equity are reclassified to earnings in the

periods when the hedged item is recognized in earnings. These earnings are included within the same line of the Consolidated

Statements of Income (Loss) as the recognized hedged item. However, when the hedged forecast transaction results in the

recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognized in other comprehensive

PACIFIC E&P


21

income and accumulated in equity are transferred from equity and included in the initial measurement of the cost of the non-

financial asset or non-financial liability.

If, upon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated with

only the intrinsic component designated as the hedging instrument, the aligned time value component will be deferred in OCI as

a cost of hedging.

Hedge accounting is discontinued when the hedging instrument expires or is sold, terminated, or exercised, or when it no longer

meets the criteria for hedge accounting. Any gain or loss recognized in other comprehensive income (intrinsic and time value

components) and accumulated in equity at that time remains in equity and is recognized in profit or loss when the forecast

transaction is ultimately recognized in profit or loss. When a forecast transaction is no longer expected to occur, the gain or loss

accumulated in equity is recognized immediately in profit or loss.

Leases

The determination of whether an arrangement is or contains a lease is based on the substance of the arrangement at inception date

based on whether the fulfillment of the arrangement is dependent on the use of a specific asset or assets or the arrangement

conveys a right to use the asset. All take-or-pay contracts are reviewed for indicators of a lease upon inception.

Finance leases, which transfer to the Company substantially all the risks and benefits incidental to ownership of the leased item,

are capitalized at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum

lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a

constant rate of interest on the remaining balance of the liability. Finance charges are recognized in the consolidated statement of

income.

Finance-leased assets are depreciated over the useful life of the asset. However, if there is no reasonable certainty that the

Company will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life

of the asset or the lease term.

Operating lease payments are recognized as an expense in the consolidated statement of income on a straight-line basis.

Asset Retirement Obligation

An asset retirement obligation is recognized when the Company has a present legal or constructive obligation as a result of past

events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount

of obligation can be made. A corresponding amount equivalent to the asset retirement obligation is also recognized as part of the

cost of the related oil and gas properties or exploration and evaluation assets. The amount recognized is the estimated cost of

decommissioning, discounted to its present value. Changes in the estimated timing or costs of decommissioning or in the discount

rate are recognized prospectively by recording an adjustment to the asset retirement obligation and a corresponding adjustment

to the properties. The unwinding of the discount on the decommissioning cost is included as a finance cost.

This accounting policy also applies to the costs that the Company deems to be “environmental liabilities” that include, but are

not limited to: the 1% provision of the investment for the use of water sources, costs of reforestation in accordance with

environmental licences and the costs of any other compensation or costs incurred in accordance with environmental licences.

Taxes

Current income tax

Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered

from or paid to taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or

substantively enacted at the reporting date.

PACIFIC E&P


22

Current income tax relating to items recognized directly in equity is recognized in equity and not in the consolidated statement

of income. Management periodically evaluates positions taken in the tax returns with respect to situations in which applicable

tax regulations are subject to interpretation and establishes provisions where appropriate.

The Company pays the majority of its income taxes in Colombia, where the statutory income tax rate is 25%. In addition, there

is an incremental 15% (2015: 14%) income tax surcharge (“CREE” being the Spanish acronym) to compensate for the elimination

of certain payroll taxes primarily related to low-income salaries (referred to as the “fairness tax”). In general, the CREE is applied

on an adjusted taxable income base, but in no case can the CREE taxable income be less than 3% of the taxpayer’s net equity as

of the preceding taxation year. The Company accounts for CREE taxes as an income tax expense or recovery.

Deferred income tax

Deferred income tax is provided using the liability method on temporary differences at the date of the consolidated statement of

financial position between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred income tax liabilities are recognized for all taxable temporary differences, except:

• Where the deferred income tax liability arises from the initial recognition of goodwill or of an asset or liability in a

transaction that is not a business combination and, at the time of the transaction, affects neither the accounting earnings

nor taxable earnings or loss; and

• With respect to taxable temporary differences associated with investments in subsidiaries, associates and interests in

joint ventures where the timing of the reversal of the temporary differences can be controlled and it is probable that the

temporary differences will not reverse in the foreseeable future.

Deferred income tax assets are recognized for all deductible temporary differences, carry forward of unused tax credits, and

unused tax losses to the extent that it is probable that taxable earnings will be available against which the deductible temporary

differences and the carry-forward of unused tax credits and unused tax losses can be utilized except:

• Where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition

of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither

the accounting earnings nor taxable earnings or loss; and

• With respect to deductible temporary differences associated with investments in subsidiaries, associates and interests in

joint ventures, deferred income tax assets are recognized only to the extent that it is probable that the temporary

differences will reverse in the foreseeable future and taxable earnings will be available against which the temporary

differences can be utilized.

The carrying amount of deferred income tax assets is reviewed at each date of the consolidated statement of financial position

and reduced to the extent that it is no longer probable that sufficient taxable earnings will be available to allow all or part of the

deferred income tax asset to be utilized. Unrecognized deferred income tax assets are reassessed at each date of the consolidated

statement of financial position and are recognized to the extent that it becomes probable that future taxable earnings will allow

the deferred tax asset to be recovered.

Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is

realized or the liability is settled and are based on tax rates (and tax laws) that have been enacted or substantively enacted at the

end of the reporting period.

Deferred income tax relating to items recognized directly in equity is recognized in equity and not in the consolidated statement

of income.

PACIFIC E&P


23

Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to set off current tax

assets against current income tax liabilities and the deferred income taxes relate to the same taxable entity and the same taxation

authority.

Revenue Recognition

Revenue from sales of oil and gas is recognized when the significant risks and rewards of ownership have been transferred. This

generally occurs when product is physically delivered, the title passes to the buyers and collection is reasonably assured.

Revenue is stated based on the Company’s share of production (after in-kind royalties) after deducting sales taxes, excise duties

and similar levies.

The Company follows the entitlements method in accounting when the share of production of a joint-interest partner is above or

below the proportionate interest. Under the entitlements method, revenue reflects the participant’s share of production regardless

of which participant has actually made the sale and invoiced the production. This is achieved by adjusting the cost of sales.

Borrowing Costs

Borrowing costs directly relating to the acquisition, construction or production of a qualifying capital project under construction

are capitalized and added to the project cost during construction until such time as the assets are substantially ready for their

intended use, i.e. when they are capable of commercial production. Where funds are borrowed specifically to finance a project,

the amount capitalized represents the actual borrowing costs incurred.

Where surplus funds are available for a short term out of money borrowed specifically to finance a project, the income generated

from such short-term investments is also capitalized and reduced from the total capitalized borrowing cost. Where the funds used

to finance a project form part of general borrowings, the amount capitalized is calculated using a weighted average of rates

applicable to relevant general borrowings of the Company during the period. All other borrowing costs are recognized in the

consolidated statement of income using the effective interest rate method.

Share-Based Compensation

The Company accounts for the granting of stock options using the fair-value method on stock options granted to officers,

employees and consultants. Share-based compensation is recorded in the consolidated statement of income for options granted

with a corresponding amount reflected in contributed surplus. Share-based compensation is the fair value of stock options at the

time of the grant and is estimated using the Black-Scholes option-pricing model. When the stock options are exercised, the

associated amounts previously recorded as contributed surplus are reclassified to common share capital. The Company has not

incorporated an estimated forfeiture rate for stock options that will not vest as all options granted are fully vested at the date of

grant.

In addition to stock options, the Company has a Deferred Share Unit (“DSU”) plan under which non-employee directors and

employees receive units in consideration for services provided to the Company. Units awarded under the DSU vest immediately

and may only be settled in cash, shares, or a combination of both upon retirement. On the grant date, the Company recognizes a

share-based compensation expense for the DSU awards at fair value with a corresponding liability. The fair value of the DSUs is

estimated using current market price and number of DSU’s issued. The liability is revalued each reporting period and the change

in fair value is recorded in share-based compensation expense (recovery).

Foreign Currency Translation

The consolidated financial statements are presented in U.S. dollars, which is also the Company’s functional currency.

Transactions denominated in a foreign currency are initially recorded at the rate of exchange on the date of the transaction.

Monetary assets and liabilities denominated in foreign currencies are translated at the closing rates on the date of the consolidated

PACIFIC E&P


24

statement of financial position. All differences are recorded in net earnings or losses. Non-monetary items are translated using

the historical exchange rates as at the dates of the initial transactions.

For a foreign operation whose functional currency is not the U.S. dollar, the foreign operation’s assets and liabilities are translated

at the closing rate as at the date of the consolidated statement of financial position, while revenue and expenses are translated

using the rate as at the time of the transaction. All exchange differences resulting from the translation are recognized in other

comprehensive income.

Earnings Per Share

The Company computes basic earnings per share using net earnings divided by the weighted average number of the common

shares outstanding. The Company computes diluted earnings per share using net earnings adjusted for the impact of the potential

dilution if outstanding stock options were exercised and exchanged for common shares. The Company follows the treasury stock

method in the calculation of diluted earnings per share. This method assumes that any proceeds received from in-the-money

options would be used to buy common shares at the average market price for the period.

Share Repurchases

When shares of the Company are repurchased for cancellation, the amount of the consideration paid, which includes directly

attributable costs net of any tax effect, is recognized as a deduction from common shares to the extent of the book value of the

shares outstanding with the excess deducted from contributed surplus.

When shares of the Company are repurchased and retained, the amount of consideration paid, which includes directly attributable

costs and net of any tax effect, is recognized as treasury shares within the equity section of the Consolidated Statement of Financial

Position.

Gross earnings

The Company uses the financial measure “Gross earnings” as management believes that the measure is an important indicator of

the Company’s ability to generate liquidity through operating earnings to fund future working capital needs, service outstanding

debt, and fund future capital expenditures.

2.3. Changes in Accounting Policies and Disclosures

There were a number of new standards and interpretations effective from January 1, 2016 that the Company applied for the first

time. The nature and impact of each new relevant standard and/or amendment is described below. Other than the changes

described below, the accounting policies adopted are consistent with those of previous financial years.

IFRS 5 Non-Current Assets Held for Sale and Discontinued Operations

Assets (or disposal groups) are generally disposed of either through sale or distribution to the owners. This amendment clarifies

that changing from one of these disposal methods to the other would not be considered a new plan of disposal; rather, it is a

continuation of the original plan. There is, therefore, no interruption of the application of the requirements in IFRS 5. This

amendment is applied prospectively. This amendment does not have any impact on the Company.

Amendments to IFRS 11 Joint Arrangements: Accounting for Acquisitions of Interests

The amendments to IFRS 11 require that a joint operator accounting for the acquisition of an interest in a joint operation in which

the activity of the joint operation constitutes a business must apply the relevant IFRS 3 Business Combinations principles for

business combination accounting. The amendments also clarify that a previously held interest in a joint operation is not

remeasured on the acquisition of an additional interest in the same joint operation if joint control is retained. In addition, a scope

exclusion has been added to IFRS 11 to specify that the amendments do not apply when the parties sharing joint control, including

the reporting entity, are under common control of the same ultimate controlling party. The amendments apply to both the

PACIFIC E&P


25

acquisition of the initial interest in a joint operation and the acquisition of any additional interests in the same joint operation and

are prospectively effective for annual periods beginning on or after January 1, 2016, with early adoption permitted. These

amendments do not have any impact on the Company.

Amendments to IAS 1 Disclosure Initiative

The amendments to IAS 1 clarify, rather than significantly change, existing IAS 1 requirements. The amendments clarify:

• The materiality requirements in IAS 1;

• That specific line items in the statement(s) of profit or loss and OCI and the statement of financial position may be

disaggregated;

• That entities have flexibility as to the order in which they present the notes to financial statements; and

• That the share of OCI of associates and joint ventures accounted for using the equity method must be presented in

aggregate as a single line item and classified between those items that will or will not be subsequently reclassified to

profit or loss.

Furthermore, the amendments clarify the requirements that apply when additional subtotals are presented in the statement of

financial position and the statement(s) of profit or loss and OCI. These amendments did not have any impact on the Company.

IAS 34 Interim Financial Reporting

This amendment clarifies that the required interim disclosures must be either in the interim condensed financial statements or

incorporated by cross-reference between the interim financial statements and wherever they are included within the interim

financial report.

The other information within the interim condensed financial statements must be available to users on the same terms as the

interim condensed financial statements and at the same time. This amendment must be applied retrospectively and did not have

any impact on the Company.

2.4. Standards Issued but Not Yet Effective

Standards issued but not yet effective up to the date of issuance of the Company’s financial statements that are likely to have an

impact on the Company are listed below. This listing is of standards and interpretations issued that the Company reasonably

expects to be applicable at a future date. The Company intends to adopt these standards when they become effective.

IFRS 2 Classification and Measurement of Share-based Payment Transactions

The IASB issued amendments to IFRS 2 Share-based Payment that address three main areas: the effects of vesting conditions on

the measurement of a cash-settled share-based payment transaction; the classification of a share-based payment transaction with

net settlement features for withholding tax obligations; and accounting where a modification to the terms and conditions of a

share-based payment transaction changes its classification from cash settled to equity settled.

Upon adoption, entities are required to apply these amendments without restating prior periods, but retrospective application is

permitted if elected for all three amendments and other criteria are met. The amendments are effective for annual periods

beginning on or after January 1, 2018, with early application permitted.

The Company plans to adopt the new standard at the effective date and is in the process of assessing the impact on its consolidated

financial statements.

PACIFIC E&P


26

IFRS 9 Financial Instruments

Classification and measurement of financial assets

All financial assets are measured at fair value on initial recognition and adjusted for transaction costs if the instrument is not

accounted for at FVTPL. Debt instruments are subsequently measured at FVTPL, amortized cost, or FVTOCI on the basis of

their contractual cash flows and the business model under which the debt instruments are held. There is a fair value option

(“FVO”) that allows financial assets on initial recognition to be designated as FVTPL if that eliminates or significantly reduces

an accounting mismatch. Equity instruments are generally measured at FVTPL. However, entities have an irrevocable option on

an instrument-by-instrument basis to present changes in the fair value of non-trading instruments in OCI without subsequent

reclassification to profit or loss.

Classification and measurement of financial liabilities

For financial liabilities designated as FVTPL using the FVO, the amount of change in the fair value of such financial liabilities

that is attributable to changes in credit risk must be presented in OCI. The remainder of the change in fair value is presented in

profit or loss unless presentation in OCI of the fair value change with respect to the liability’s credit risk would create or enlarge

an accounting mismatch in profit or loss. All other IAS 39 Financial Instruments: Recognition and Measurement classification

and measurement requirements for financial liabilities have been carried forward into IFRS 9 including the embedded derivative

separation rules and the criteria for using the FVO.

Impairment

The impairment requirements are based on an expected credit loss (“ECL”) model that replaces the IAS 39 incurred loss model.

The ECL model applies to debt instruments accounted for at amortized cost or at FVTOCI, most loan commitments, financial

guarantee contracts, contract assets under IFRS 15 Revenue from Contracts with Customers, and lease receivables under IAS 17

Leases. Entities are generally required to recognize 12-month ECL on initial recognition (or when the commitment or guarantee

was entered into) and thereafter as long as there is no significant deterioration in credit risk. However, if there has been a

significant increase in credit risk on an individual or collective basis, then entities are required to recognize lifetime ECL. For

trade receivables, a simplified approach may be applied whereby the lifetime ECL is always recognized.

The Company previously adopted IFRS 9 (2013) and plans to adopt the amendments to IFRS 9 (2014) at the effective date; the

Company is currently in the process of assessing the impact on its consolidated financial statements. The amendments are

effective for annual periods beginning on or after January 1, 2018.

Early application is permitted for reporting periods beginning after the issue of IFRS 9 on July 24, 2014 by applying all of the

requirements in this standard at the same time. Alternatively, entities may elect to early apply only the requirements for the

presentation of gains and losses on financial liabilities designated as FVTPL without applying the other requirements in the

standard.

IFRS 15 Revenue from Contracts with Customers

IFRS 15 replaces all existing revenue requirements in IFRS (IAS 11 Construction Contracts, IAS 18 Revenue, IFRIC 13 Customer

Loyalty Programmes, IFRIC 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of Assets from Customers,

and SIC 31 Revenue – Barter Transactions Involving Advertising Services) and applies to all revenue arising from contracts with

customers unless the contracts are in the scope of other standards such as IAS 17. Its requirements also provide a model for the

recognition and measurement of gains and losses on disposal of certain non-financial assets, including property, equipment and

intangible assets. The standard outlines the principles an entity must apply to measure and recognize revenue. The core principle

is that an entity will recognize revenue at an amount that reflects the consideration to which the entity expects to be entitled in

exchange for transferring goods or services to a customer.

The principles in IFRS 15 will be applied using a five-step model:

PACIFIC E&P


27

1. Identify the contract(s) with a customer

2. Identify the performance obligations in the contract

3. Determine the transaction price

4. Allocate the transaction price to the performance obligations in the contract

5. Recognize revenue when (or as) the entity satisfies a performance obligation

The standard requires entities to exercise judgement and take into consideration all of the relevant facts and circumstances when

applying each step of the model to contracts with their customers. The standard also specifies how to account for the incremental

costs of obtaining a contract and the costs directly related to fulfilling a contract. Application guidance is provided in IFRS 15 to

assist entities in applying its requirements to certain common arrangements including licences of intellectual property, warranties,

rights of return, principal-versus-agent considerations, options for additional goods or services, and breakage. The new standard

will apply for annual periods beginning on or after January 1, 2018. Entities can choose to apply the standard using either a full

retrospective approach with some limited relief provided, or a modified retrospective approach. Early application is permitted

and must be disclosed.



IFRS 16 Leases

The scope of IFRS 16 includes leases of all assets with certain exceptions. A lease is defined as a contract or part of a contract

that conveys the right to use an asset (the underlying asset) for a period of time in exchange for consideration. IFRS 16 requires

lessees to account for all leases under a single on-balance sheet model in a similar way to finance leases under IAS 17. The

standard includes two recognition exemptions for lessees – leases of ‘low-value’ assets (i.e., personal computers), and short-term

leases (i.e., leases with a lease term of 12 months or less). At the commencement date of a lease, a lessee will recognize a liability

to make lease payments (i.e., the lease liability) and an asset representing the right to use the underlying asset during the lease

term (i.e., the right-of-use asset). Lessees will be required to separately recognize the interest expense on the lease liability and

the depreciation expense on the right-of-use asset. Lessees will be required to remeasure the lease liability upon the occurrence

of certain events (i.e., a change in the lease term or a change in future lease payments resulting from a change in an index or rate

used to determine those payments). The lessee will generally recognize the amount of the remeasurement of the lease liability as

an adjustment to the right-of-use asset. Lessor accounting is substantially unchanged from today’s accounting under IAS 17.

Lessors will continue to classify all leases using the same classification principle as in IAS 17 and distinguish between two types

of leases: operating and finance leases. The new standard will apply for annual periods beginning on or after January 1, 2019. A

lessee can choose to apply the standard using either a full retrospective or a modified retrospective transition approach. The

standard’s transition provisions permit certain reliefs. Early application is permitted, but not before an entity applies IFRS 15.



IAS 7 Statement of Cash Flows

The amendments to IAS 7 Statement of Cash Flows are part of the IASB’s Disclosure Initiative and require an entity to provide

disclosures that enable users of financial statements to evaluate changes in liabilities arising from financing activities, including

both changes arising from cash flows and non-cash changes. The amendments are effective for annual periods beginning on or

after January 1, 2017, with early application permitted.



IAS 12 Income Taxes

The IASB issued the amendments to IAS 12 Income Taxes to clarify the accounting for deferred tax assets for unrealized losses

on debt instruments measured at fair value. The amendments clarify that an entity needs to consider whether tax law restricts the

PACIFIC E&P


28

sources of taxable profits against which it may make deductions on the reversal of that deductible temporary difference.

Furthermore, the amendments provide guidance on how an entity should determine future taxable profits and explains in which

circumstances taxable profit may include the recovery of some assets for more than their carrying amount. The amendments are

effective for annual periods beginning on or after January 1, 2017. Entities are required to apply the amendments retrospectively.

However, on initial application of the amendments, the change in the opening equity of the earliest comparative period may be

recognized in opening retained earnings (or in another component of equity, as appropriate) without allocating the change between

opening retained earnings and other components of equity. Entities applying this relief must disclose that fact. Early application

is permitted. If an entity applies the amendments for an earlier period, it must disclose that fact.



3. Composition of the Company

The following table summarizes the Company's significant subsidiaries and equity associates, the location of their registered

offices, the Company's interest, and the method of consolidation.

(1) ODL, Bicentenario and Petroelectrica are entities held by Pacific Midstream Ltd. Refer to Note 4.

4. Material Partly-owned Subsidiary

Pacific Midstream Ltd. (“PM”)

PM is the holding company for a number of the Company’s pipeline and power transmission assets, including a 35% interest in

the ODL pipeline, a 41.5% interest in the Bicentenario pipeline, and a 100% interest in Petroelectrica, a power transmission

entity. The Company has fully consolidated PM and has recognized a non-controlling interest in the equity statement of its

Consolidated Statement of Financial Position as a result of the minority interest held by the International Finance Corporation

and its associated entities (collectively the “IFC”).

Registered Recognition

Company Office Method 2016 2015

Pacific Exploration & Production Corporation Canada Parent holding company

Subsidiaries

Pacific E&P Holdings Corp. Switzerland Consolidated 100% 100%

Pacific Midstream Ltd. Bermuda Consolidated 63.64% 63.64%

Major International Oil S.A. Panama Consolidated 100% 100%

Meta Petroleum AG Switzerland Consolidated 100% 100%

Pacific Stratus Energy Colombia Corp. Panama Consolidated 100% 100%

C&C Energia Holding SRL Barbados Consolidated 100% 100%

Petroelectrica de los Llanos Ltd. (1) Bermuda Consolidated 100% 100%

Pacific Off Shore Perú S.R.L. Peru Consolidated 100% 100%

Pacific Brasil Exploração e Produção de Óleo e Gás Ltda. Brazil Consolidated 100% 100%

Pacific E&P International Holdings, S.a.r.l. Luxembourg Consolidated 100% 100%

Pacific Global Capital S.A. Luxembourg Consolidated 100% 100%

CGX Energy Inc. Canada Consolidated n/a 53.64%

Investments in associates

ODL Finance S.A. (1) Panama Equity method 35.00% 35.00%

Oleoducto Bicentenario de Colombia S.A.S. (1) Colombia Equity method 43.03% 43.03%

Interamerican Energy Corp. Panama Equity method 21.09% 21.09%

Pacific Infrastructure Ventures Inc. British Virgin Islands Equity method 41.77% 41.79%

CGX Energy Inc. Canada Equity method 45.61% n/a

Joint arrangements

Maurel and Prom Colombia B.V. Netherlands Joint operation 49.999% 49.999%

Percentage Interest

As at December 31

Parent holding company

PACIFIC E&P


29

The financial information of PM is provided below:

As at December 31, 2016, the carrying value of the non-controlling interest for PM was $105 million (2015: $129 million).

CGX Energy Inc. (“CGX”)

As of December 31, 2015, the Company controlled CGX through its 53.7% interest, and accounted for CGX as a fully

consolidated subsidiary with a non-controlling interest for $19 million. See further details in Note 19.

5. Segmented Information

The Company is organized into business units based on the main types of activities and has two reportable segments as at

December 31, 2016: the exploration, development, and production of heavy crude oil and gas in Colombia and Peru. The

Company’s assets and operations in other countries have been in early stages of development and are not significant and therefore

are not considered a reportable segment as at December 31, 2016. The Company manages its operations to reflect differences in

the regulatory environments and risk factors for each country.


2016 2015

Current assets 16,704$ 19,093$

Non-current assets 385,241 461,489

Total assets 401,945$ 480,582$

Current liabilities 111,084$ 106,222$

Non-current liabilities 1,354 21,012

Total liabilities 112,438 127,234

Equity 289,507 353,348

Total liabilities and equity 401,945$ 480,582$

2016 2015

Revenue 30,956$ 29,097$

Other income, net 33,911 16,984

Net income 64,867$ 46,081$


As at December 31, 2016 Corporate Colombia Peru Others Total

Cash and cash equivalents 259,458$ 123,445$ 4,543$ 1,653$ 389,099$

Non-current assets 18,933 1,792,200 36,751 62,562 1,910,446

278,391$ 1,915,645$ 41,294$ 64,215$ 2,299,545$

As at December 31, 2015 Corporate Colombia Peru Others Total

Cash and cash equivalents 157,505$ 154,296$ 9,563$ 21,296$ 342,660$

Non-current assets 20,014 2,414,168 200,795 65,875 2,700,852

177,519$ 2,568,464$ 210,358$ 87,171$ 3,043,512$

PACIFIC E&P


30

The selected Consolidated Statement of Income (Loss) components by reporting segment are as follows:

The Company’s revenue based on the geographic location of customers is as follows:

Year ended December 31, 2016 Colombia Peru Corporate

Other Non-Reportable

SegmentsTotal

Oil and gas sales 1,361,412$ 37,708$ -$ -$ 1,399,120$

Trading sales 12,591 - - - 12,591

Oil & gas operating cost 785,738 60,147 - - 845,885

Purchase of oil for trading 11,515 - - - 11,515

Underlift (34,228) (636) - - (34,864)

Fees paid on suspended pipeline capacity 105,129 - - - 105,129

Depletion, depreciation, amortization 518,174 54,208 232 3,371 575,985

General and administrative 99,790 6,995 24,095 13,658 144,538

Impairment and exploration expenses 301,327 170,972 (5,015) 9,721 477,005

Restructuring and severance costs 10,355 1,691 132,860 9,949 154,855

Finance costs (income) 57,657 (2,120) 141,686 (5,978) 191,245

Share of (gain) loss of equity-accounted investees (72,406) - 9,566 - (62,840)

Income tax expense 34,082 47 740 1,306 36,175

Net (loss) income (590,482)$ (242,354)$ 3,344,454$ (47,807)$ 2,463,811$

Year ended December 31, 2015 Colombia Peru Corporate

Other Non-Reportable

SegmentsTotal

Oil and gas sales 2,634,614$ 53,473$ -$ -$ 2,688,087$

Trading sales 136,459 - - - 136,459

Oil & gas operating cost 1,229,321 61,921 - - 1,291,242

Purchase of oil for trading 128,948 - - - 128,948

Overlift 34,809 636 - - 35,445

Fees paid on suspended pipeline capacity 123,818 - - - 123,818

Depletion, depreciation, amortization 1,505,107 20,936 710 2,263 1,529,016

General and administrative 132,295 9,493 32,633 28,732 203,153

Impairment and exploration expenses 3,531,236 680,149 5,025 690,799 4,907,209

Restructuring and severance costs 9,167 389 8,300 455 18,311

Finance costs (income) 9,383 5,885 420,689 (1,111) 434,846

Share of (gain) loss of equity-accounted investees (23,902) - 2,365 - (21,537)

Income tax (recovery) expense (457,664) (8,884) - 34 (466,514)

Net loss (3,544,439)$ (728,473)$ (487,432)$ (722,627)$ (5,482,971)$

2016 2015

United States 1,049,854$ 2,033,206$

China 208,033 491,314

Colombia 90,488 137,968

Peru 53,703 33,683

Spain 3,801 35,831

Malaysia - 52,559

Ivory Coast - 36,095

Other countries 5,832 3,890

Total sales 1,411,711$ 2,824,546$


PACIFIC E&P


31

6. Oil & Gas Operating Costs

7. Fees Paid on Suspended Pipeline

The Bicentenario pipeline (Note 19) has experienced periodic suspensions following security-related disruptions in recent years.

For the year ended December 31, 2016, the net fees paid relating to the periods of disrupted pipeline capacity were $105.1 million

(2015: $123.8 million).

8. Equity Tax

Effective January 1, 2015, the Colombian Congress introduced a new wealth tax that is calculated on the taxable base (net equity)

in excess of COP$1 billion ($0.4 million) as at January 1 of the applicable taxation year. The applicable rates for January 1,

2015, 2016, and 2017 are 1.15%, 1.00% and 0.40%, respectively. Taxable base is calculated based on the net equity as of January

1, 2015, with certain annual inflation-based adjustments. Pursuant to IAS 37 Provisions, Contingent Liabilities and Contingent

Assets and IFRIC 21 Levies, in the current year the Company has not made an accrual for future years. The 2016 wealth tax was

estimated at $26.9 million (2015: $39.1 million), and recorded as an expense in the Consolidated Statement of Income (Loss). In

May 2016, the Company made the first payment of $12.8 million (2015: $20.5 million), and in September 2016 made the second

payment of the remaining $14.1 million (2015: $18.6 million).

9. Income Tax

A reconciliation between income tax expense and the product of accounting profit multiplied by the Company's domestic tax rate

is provided below:

2016 2015

Oil and gas production costs 335,765$ 472,466$

Transportation costs 460,605 657,270

Dilution costs 55,108 113,141

Other costs (5,593) 48,365

Total cost 845,885$ 1,291,242$


2016 2015

Net income (loss) before income tax 2,499,986$ (5,949,485)$

Colombian statutory income tax rate 40% 39%

Income tax expense (recovery) at statutory rate 999,994$ (2,320,299)$

Increase (decrease) in income tax provision resulting from:

Other non-deductible expenses 9,710$ 52,534$

Share-based compensation (2,112) (541)

Differences in tax rates in foreign jurisdictions (444,831) 172,585

Losses for which no tax benefit is recognized 231,666 301,585

Additional presumptive taxable income 218,256 138,823

Debt extinguishment and conversion (960,517) -

Changes in deferred income tax not recognized (15,991) 1,188,799

Income tax expense (recovery) 36,175$ (466,514)$

Current income tax expense 42,522$ 50,226$

Deferred income tax recovery:

Relating to origination and reversal of temporary differences (6,347) (516,740)

Income tax expense (recovery) 36,175$ (466,514)$


PACIFIC E&P


32

The Company’s deferred tax relates to the following:

The Canadian statutory combined income tax rate was 26.5% as at December 31, 2016 and December 31, 2015.

The Colombian statutory tax rate as at December 31, 2016 was 40% (2015: 39%), which includes the general income tax rate of

25% (2015: 25%), and the fairness tax (“CREE”) rate of 15% (2015: 14%). The wealth tax on net equity was 1.5% as at January

1, 2015, 1% as at January 1, 2016, and 0.4% as at January 1, 2017.

On December 29, 2016, the Colombian Congress enacted a structural tax reform whereby it abolished the CREE tax as at January

1, 2017, while modifying the income tax rates to adjust for this change. Effectively, the Congress has maintained the previously

set corporate tax rates for Colombian source income at 40% in 2017, 37% in 2018, and 33% in 2019 and subsequent taxation

years. However, these rates will apply to a broader taxable base due to limitations and modifications on certain deductions.

In addition, the tax reform increased the minimum tax for 2017 from 3% to 3.5%, and introduced a dividend withholding tax on

previously taxed profits of 5% starting in 2017.

The Peruvian statutory income tax rate was 28% as at December 31, 2016 and December 31, 2015. The Peruvian income tax

rate for Block Z-1 was 22% as at December 31, 2016 and December 31, 2015. Starting January 1, 2017, the statutory income tax

rate will rise to 29%.

The Company’s cumulative effective tax rate (income tax expenses as a percentage of net earnings before income tax) was 1.45%

for the year ending December 31, 2016 (2015: 7.84%).

As at December 31, 2016, non-capital losses totalled $608 million (December 31, 2015: $708 million) in Canada and expire

between 2026 and 2036. Capital losses, which do not expire, totalled $307 million as at December 31, 2016 (December 31, 2015:

$5 million). No deferred tax assets have been recognized with respect to the non-capital and capital losses as at December 31,

2016 (December 31, 2015: nil).

In Colombia, non-capital losses totalled $840 million (December 31, 2015: $200 million). No deferred tax assets have been

recognized in respect of these losses. In Peru, non-capital losses totalled $175 million (December 31, 2015: $167.2 million) and

expire between 2017 and 2019. No deferred tax assets have been recognized in respect of these losses.

The temporary differences associated with investments in subsidiaries and joint ventures, for which a deferred tax liability has

not been recognized, amounted to approximately $0.7 billion as at December 31, 2016 (December 31, 2015: $3.4 billion).


2016 2015

Oil and gas properties and equipment -$ (10,120)$

Other - 3,812

Deferred tax liability -$ (6,308)$


2016 2015

Beginning of year (6,308)$ (523,634)$

Recognized in deferred income tax (recovery) expense

Tax loss carry-forwards - (35,199)

Oil and gas properties and equipment 10,120 473,040

Other (3,812) 79,485

End of the year -$ (6,308)$

PACIFIC E&P


33

10. Earning (Loss) Per Share

Earning (loss) per share amounts are calculated by dividing the net income (loss) for the period attributable to shareholders of the

Company by the weighted average number of shares outstanding during the period.

(1) The December 31, 2015 balance was adjusted in accordance with IAS 33 for the 1000,000-to-1 share consolidation as a result of the implementation of the Restructuring

Transaction (Note 1).

DSUs, which give the holder the right to receive either cash, shares or a combination of both are dilutive and have been included

in the diluted weighted average number of common shares.

11. Deferred Revenue

In 2015, the Company received $350 million (less $0.85 million in fees) in cash in exchange for the delivery of 12 million barrels

of crude oil between April 2015 and March 2016. The cash was recognized as a deferred revenue liability and was amortized and

recognized as revenue upon the monthly delivery of the crude oil. The deferred revenue balance was fully amortized as at

December 31, 2016 (December 31, 2015: $74.8 million).

12. Restricted Cash

Short-term restricted cash corresponds mainly to trust accounts in favour of Colombian trade creditors and term deposit to cover

future commitments (refer to Note 1). Long-term restricted cash is related mainly to escrow accounts for future abandonment

obligations. As at December 31, 2016, the Company has $61 million (December 2015: $18.1 million) and $52.7 million

(December 2015: $17.7 million), in short-term and long-term restricted cash, respectively.

13. Inventories

14. Assets Held for Sale

During the year ended December 31, 2016, the Company commenced a plan to sell its interest in some exploration assets, oil and

gas properties and lands located in Colombia, Peru, and Brazil. In accordance with IFRS 5 Non-current Assets Held for Sale and

Discontinued Operations, the Company has recognized these assets at lower of its carrying amount and fair value less costs of

disposal, and recorded a loss of $1.2 million.

2016 2015

Net income (loss) attributable to shareholders of the Company 2,448,523$ (5,461,859)$

Basic weighted average number of shares (1) 50,002,363 3,150

Effects of dilution 16,634 -

Diluted weighted average number of shares (1) 50,018,997 3,150

Basic income (loss) per share attributable to equity holders of the parent 48.97 (1,733,923)

Diluted income (loss) per share attributable to equity holders of the parent 48.95 (1,733,923)


2016 2015

Crude oil and gas 8,049$ 3,077$

Materials and supplies 30,560 24,334

38,609$ 27,411$

As at December 31

PACIFIC E&P


34

The assets held for sales are as follows:

The Company expects to complete the divestment of the above assets during 2017.

15. Oil and Gas Properties

Note Amount

Exploration and evaluation assets

Brazil 16,149$

Colombia Central 4,498

16 20,647$


Peru 17,986

Colombia Central 6,164

15 24,150$

Total 44,797$

Cost Note Amount

Cost as at December 31, 2014 10,614,900$

Additions 557,263

Transfer from exploration and evaluation assets 16 69,184

Disposals (25,793)

Sales (15,422)

Currency translation adjustment (97,565)

Change in asset retirement obligation (37,001)


Additions 125,330

Relinquishment of properties and disposals (3,808,747)

Transfer to assets held for sale 14 (29,575)

Currency translation adjustment 11,708

Change in asset retirement obligation 11,368


Accumulated depletion and impairment Note Amount

Accumulated depletion and impairment as at December 31, 2014 5,484,033$

Charge for the year 1,452,395

Disposals (25,793)

Impairment 21 2,344,587

Sales (4,918)


Accumulated depletion and impairment as at December 31, 2015 9,246,847

Charge for the year 515,141

Relinquishment of properties and disposals (3,808,747)

Impairment 21 869,793

Reversal of previously recognized impairments 21 (631,401)



Accumulated depletion and impairment as at December 31, 2016 6,183,982$

Net book value Amount

As at December 31, 2015 1,818,719$

As at December 31, 2016 1,191,668$

PACIFIC E&P


35

On June 30, 2016, the joint operating agreements for the Rubiales and Piriri fields expired and the fields were returned to

Ecopetrol, and all associated contracts were terminated. All net book values associated with these fields have been fully depleted,

and the Company has recorded all obligations related to the termination.

During the year ended December 31, 2016, oil and gas assets were depleted over the Company’s proved reserves (2015: proved

and probable reserves) to align with the Company’s ability to fund oil and gas production.

Included in the amount subject to depletion is $0.7 billion (December 31, 2015: $1.4 billion) of estimated future development

costs that are required to bring proved undeveloped reserves to production (2015: proved undeveloped and probable reserves).

$108 million in oil and gas properties were under construction as at December 31, 2016 (December 31, 2015: $184 million) and

as such are not currently subject to depletion.

16. Exploration and Evaluation Assets

On September 27, 2016, the Company reached an agreement with its partner Karoon Gas Australia Ltd. (“Karoon”) to sell the

Company’s 35% working interest in its joint concession agreements in Brazil, for cash consideration of $15.5 million on closing.

In addition, the Company will receive a subsequent payment of $5 million should commercial production reach 1 million barrels

of oil or oil equivalents on these concessions. The sale is subject to Brazilian regulatory approval as of December 31, 2016, and

as such the Company has not recognized the transaction (Refer to Note 14).

On October 14, 2016, the Company entered into a farm-out agreement with its partner Queiroz Galvão Exploração e Produção

S.A. (“QGEP”) for the transfer of the participating interests in certain contracts to QGEP. Pursuant to the agreement, the

Company paid QGEP the outstanding cash calls related to minimum work commitments for these blocks in the amount of

approximately $16 million. In addition, $10 million has been held in escrow to be released to QGEP upon the satisfaction of

certain conditions, in exchange for the Company being released from all future work commitments by $76.3 million. The sale

was subject to Brazilian regulatory approval as of December 31, 2016, and as such the Company has not recognized the

transaction (Refer to Note 14). As a result of the exit from contracts, the Company also will be released from approximately $40

million of letter of credit requirements.

On November 30, 2016, the Company reached an agreement with CEPSA Peruana S.A.C. (“CEPSA”) to sell the\ Company’s

30% working interest in the concession agreements in Lot 131 in Peru. The Company will receive from CEPSA $17.8 million in

cash as consideration on closing. The sale is subject to Peruvian regulatory approval, and as such the Company has not recognized

the transaction as at December 31, 2016 (Refer to Note 14).

Notes Amount

Cost net of impairment as at December 31, 2014 2,243,481$

Additions 146,414

Transfer to oil and gas properties 15 (69,184)

Reclassified to other assets (51,267)

Impairment and exploration expenses 21 (2,252,936)

Disposals (1,558)

Change in asset retirement obligation (14,950)

Cost net of impairment as at December 31, 2015 -$

Additions 31,202

Disposals (216)

Effect of deconsolidation of subsidiary (245)


Impairment 21 (51,950)

Reversal of previously recognized impairments 21 29,648

Change in asset retirement obligation 12,208

Cost net of impairment as at December 31, 2016 -$

PACIFIC E&P


36

17. Plant and Equipment

18. Intangible Assets

Capacity rights comprise the rights to the available capacity of the OCENSA pipeline system in Colombia, and the right to

available capacity at the crude blending station. The OCENSA right is amortized based on the higher between the usages of the

160 million barrel capacity or straight-line method, over the term of the agreement.

Cost Note Land & buildings

Assets under

construction

Other plant &

equipment Total

Cost as at December 31, 2014 60,518$ 7,065$ 195,530$ 263,113$

Additions 2,717 186 5,772 8,675

Disposals - - (4,145) (4,145)

Cost as at December 31, 2015 63,235$ 7,251$ 197,157$ 267,643$

Additions 405 - 3,825 4,230

Effect of deconsolidation of subsidiary - (7,251) - (7,251)

Relinquishment of properties - - (2,813) (2,813)

Disposals (1,832) - (7,783) (9,615)

Currency translation adjustment (64) - 223 159

Cost as at December 31, 2016 61,744$ -$ 190,609$ 252,353$

Accumulated depreciation and impairment

Accumulated depreciation and impairment as at December 31, 2014 35,744$ 4,200$ 67,031$ 106,975$

Charge for the year 12,306 - 33,120 45,426

Disposals - - (2,988) (2,988)

Accumulated depreciation and impairment as at December 31, 2015 48,050$ 4,200$ 97,163$ 149,413$

Charge for the year 8,412 - 22,908 31,320

Impairment 21 - - 33,565 33,565

Disposals (1,130) - (7,131) (8,261)

Currency translation adjustment (213) - 140 (73)

Relinquishment of properties - - (2,813) (2,813)

Effect of deconsolidation of subsidiary - (4,200) - (4,200)

Accumulated depreciation and impairment as at December 31, 2016 55,119$ -$ 143,832$ 198,951$

Net book value

As at December 31, 2015 15,185$ 3,051$ 99,994$ 118,230$

As at December 31, 2016 6,625$ -$ 46,777$ 53,402$

Cost Capacity Rights

Cost as at December 31, 2014, 2015 and 2016 190,000$

Accumulated amortization Amount

Accumulated amortization as at December 31, 2014 127,868$





Net book value Amount

As at December 31, 2015 40,877$

As at December 31, 2016 14,800$

PACIFIC E&P


37

19. Investments in Associates

Set out below are the investments in associates as at December 31, 2016. Investments in associates are accounted for using the

equity method, with the Company’s share of the associates’ net income or loss recognized in the Consolidated Statement of

Income (Loss).

ODL Finance S.A. (“ODL”)

The Company’s investment represents a 35% interest in ODL, a Panamanian company with a Colombian branch that has

constructed an oil pipeline for the transportation of heavy crude oil produced from the Rubiales field. The remaining 65% interest

is owned by Ecopetrol, the national oil company of Colombia. ODL’s functional currency is the Colombian peso and the currency

translation adjustment upon conversion to U.S. dollars has been recorded in other comprehensive income.

Oleoducto Bicentenario de Colombia (“Bicentenario”)

Bicentenario is a corporation established and owned by a consortium of oil producers operating in Colombia led by Ecopetrol.

The Company owns 43.03% of Bicentenario, which operates a private-use oil pipeline in Colombia between Casanare and

Coveñas. Bicentenario’s functional currency is the Colombian peso and the currency translation adjustment upon conversion to

U.S. dollars has been recorded in other comprehensive income.

Pacific Infrastructure Ventures Inc. (“PII”)

PII is a BVI company established for the purpose of developing an export terminal, an industrial park, and a free trade zone in

Cartagena. The Company’s interest in PII is 41.77% (December 31, 2015: 41.79%), and it holds two board seats in PII. The

functional currency of PII is the U.S. dollar.

Interamerican Energy Corp. (“Interamerican,” formerly Pacific Power Generation Corp.)

The Company’s investment in Interamerican represents a 21.09% (December 2015: 24.9%) indirect interest in Promotora de

Energia Electrica de Cartagena & Cia, S.C.A. E.S.P. (“Proelectrica”). Proelectrica is a private, Cartagena, Colombia-based 90-

megawatt electrical utility peak-demand supplier to the local Cartagena utility. The functional currency of Interamerican is the

U.S. dollar.

During the year ended December 31, 2016, the Company recognized an impairment charge of $5.8 million when it determined

the carrying value of its investment in Interamerican was in excess of the fair value calculated with reference to a market-based

transaction between independent parties. During the year ended December 31, 2015, the Company’s interest in Interamerican

reduced to 21.09% as a result of the Company entering into an agreement to sell 4.5 million shares of Interamerican for $522

thousand, which resulted in a $3.1 million loss recognized in the Consolidated Statement of Income (Loss).

ODL Bicentenario PII Interamerican CGX CRC Total

As at December 31, 2014 $ 162,353 $ 219,020 $ 161,781 $ 23,061 $ - $ 825 $ 567,040

Investment - - 4,638 (3,671) - - 967

Gain (loss) from equity investments 38,237 46,535 (60,873) 1,562 - (661) 24,800

Dividends (25,680) (30,990) - - - - (56,670)

Foreign currency translation (39,838) (36,278) (11,641) - - - (87,757)

Impairment of equity investments - - - - - (114) (114)

As at December 31, 2015 $ 135,072 $ 198,287 $ 93,905 $ 20,952 $ - $ 50 $ 448,266

Investment - - 25 2,318 6,348 - 8,691

Gain (loss) from equity investments 39,125 60,717 (27,436) (1,412) (2,332) - 68,662

Dividends (58,832) (61,623) - - - - (120,455)

Foreign currency translation 7,879 (6,879) 14,856 - - - 15,856

Impairment of equity investments - - - (5,772) - (50) (5,822)

As at December 31, 2016 $ 123,244 $ 190,502 $ 81,350 $ 16,086 $ 4,016 $ - $ 415,198

PACIFIC E&P


38

CGX

CGX is a company listed on the TSX Venture Exchange and is involved in the exploration and development of petroleum and

natural gas in Guyana. Prior to January 21, 2016, the Company had control of CGX by way of a 53.7% interest, and accounted

for it as a fully consolidated subsidiary. The functional currency of CGX is the U.S. dollar.

On January 21, 2016, pursuant to a contract settlement agreement, the Company’s interest was reduced to 45.61% and determined

it no longer held control over CGX. Upon loss of control, the Company derecognized the assets and liabilities of CGX from the

consolidated statement of financial position. Following the deconsolidation, CGX has been accounted for as an equity investment.

As such, an investment in an associate was recognized at fair value, and a gain of approximately $15.6 million was recognized

in other (expense) income in the Consolidated Statement of Income (Loss).

As at December 31, 2016, the fair value of the investment in CGX, estimated using the last traded price of C$0.13 (December

31, 2015: C$0.23) per common share, was $5.0 million (December 31, 2015: $11.6 million).

Caribbean Resources Corporation (formerly Pacific Coal Resources Ltd.) (“CRC”)

CRC is engaged in the acquisition and development of coal mining assets and related businesses in Colombia. During the year

ended December 31, 2016, the Company recognized an impairment charge of $50 thousand when it determined that the value of

its investment in CRC was nil when CRC voluntarily delisted from the TSX Venture Exchange. In October 2016, the Company’s

equity interest was diluted to 1%, and as such the Company lost its right to nominate a director to the board of directors of CRC.

The Company has determined it no longer holds significant influence over CRC and as a result will no longer be accounting for

its interest in CRC as an equity investment. As at December 31, 2016, the Company’s interest in CRC is 1% (December 31, 2015:

8.49%). The functional currency of CRC is the U.S. dollar.

Dividends

During the year ended December 31, 2016, the Company received cash dividends of $120.4 million from its equity-accounted

investments (2015: $56.7 million). The Company holds a 63.64% interest in PM, which is the holding company for a number of

the Company’s pipeline and power transmission assets, including a 35% interest in the ODL pipeline, a 43% interest in the

Bicentenario pipeline, and a 100% interest in Petroelectrica. During the year ended December 31, 2016, the Company distributed

$41.8 million (2015: $26.6 million) in dividends to the minority interests of PM.

The table below summarizes the financial information for the Company’s significant investments in associates (figures represent

100% of the underlying entities’ interest):

ODL Bicentenario PII

As at and for the year ended December 31, 2016

Current assets 105,042$ 171,086$ 57,380$

Non-current assets 572,505 1,108,399 625,431

Current liabilities (128,744) (231,603) (179,436)

Non-current liabilities (196,676) (605,162) (308,619)

Equity 352,127$ 442,720$ 194,756$

Proportion of the Company´s ownership(1) 35.00% 43.03% 41.77%

Carrying amount of the investment 123,244$ 190,502$ 81,350$

Revenue 338,577$ 384,737$ 69,820$

Expenses (226,790) (243,632) (135,503)

Net income 111,787 141,105 (65,683)

Company´s share of the profit (loss) for the year 39,125$ 60,717$ (27,436)$

PACIFIC E&P


39

(1) ODL and Bicentenario are entities held by Pacific Midstream Ltd., an entity held 63.64% by Pacific Exploration & Production Corporation.

20. Other Assets

Long Term Receivables, Investments and Advances

These assets include a variety of items such as non-trade receivables from associates, advances for pipeline usage, and other long-

term financial assets.

The Company has a loan receivable from PII of $72.4 million with a carrying value of $38.9 million (representing the present

value) as at December 31, 2016 ($72.4 million as at December 31, 2015). The loan receivable from PII is guaranteed by PII’s

pipeline project and port and bears interest that ranges from LIBOR + 2% to 7% per annum. No interest income was recognized

during the year ended December 31, 2016 (2015: $5 million).

During the year ended December 31, 2015, the Company decided to withdraw from its participation in the exploratory blocks in

Papua New Guinea. As per the terms of the withdrawal, the Company agreed to accept a receivable of $96 million (present value

of $56.1 million and $51.1 million as at December 31, 2016 and December 31, 2015, respectively), payable in six years from its

partner in the blocks.

During the year ended December 31, 2016, the Company recorded impairment charges of $19.3 million (2015: nil) relating to

certain advances for port and throughput services that would not be recovered. See Note 21.

Long-Term Recoverable VAT

This amount includes recoverable VAT that the Company expects to receive more than one year after the end of the reported

period.

ODL Bicentenario PII

As at and for the year ended December 31, 2015

Current assets 191,403$ 155,581$ 103,049$

Non-current assets 589,531 1,127,420 645,931

Current liabilities (251,169) (176,932) (179,465)

Non-current liabilities (143,844) (645,257) (344,808)

Equity 385,921$ 460,812$ 224,707$

Proportion of the Company´s ownership(1) 35.00% 43.03% 41.79%

Carrying amount of the investment 135,072$ 198,287$ 93,905$

Revenue 368,659$ 381,645$ 60,643$

Expenses (259,410) (273,500) (206,305)

Net income (loss) 109,249 108,145 (145,662)

Company´s share of the profit (loss) for the year 38,237$ 46,535$ (60,873)$

2016 2015

Long-term receivables 105,460$ 60,469$

Long-term recoverable VAT 26,989 64,958

Long-term withholding tax 27,439 -

Advances 21,782 43,189

Investments 962 1,125

Bicentenario prepayments - 87,278

182,632$ 257,019$

As at December 31

PACIFIC E&P


40

During the year ended December 31, 2016, the Company recorded an impairment charge of $59.6 million (2015: $10.9 million)

relating to certain receivables, the majority of which related to VAT receivable in Peru. As a result of updating its production

forecasts, the Company determined that it was more likely than not that the VAT receivable in Peru would not be recovered

through future production on certain blocks. See Note 21.

Bicentenario Prepayments

Prepayments include advances for the usage of the Bicentenario pipeline, which will be amortized against the barrels transported.

As at December 31, 2016, based on updated production forecasts, the Company believed these advances paid for usage of the

Bicentenario pipeline would not be utilized. As a result, the balance has been fully impaired and it was recognized in impairment

and exploration expenses in the Consolidated Statement of Income (Loss). During the year ended December 31, 2016, the

Company recorded impairment charges of $87.3 million (2015: nil). See further details in Note 21.

21. Impairment and Exploration Expenses

Impairment and Impairment Reversal

The Company assesses at the end of each reporting period whether there is any indication, from external and internal sources of

information, that an asset or CGU may be impaired, or if there is any indication that previously recognized impairment losses

may no longer exist or may have decreased. In performing the assessment, the Company considers changes in the market,

economic and legal environments in which the Company operates that are not within its control and affect the recoverable amount

of the oil and gas, exploration and evaluation properties.

The Company’s impairment tests of oil and gas and exploration and evaluation assets are performed at the CGU level. The

recoverable amount is calculated based on the higher of value-in-use and fair value less costs of disposal. The recoverable amount

as of December 31, 2016 was determined based on the fair value less costs of disposal (2015: value-in-use).

During the first quarter of 2016 and as a result of the Restructuring Transaction entered into on April 19, 2016 (Note 1 –

“Comprehensive Restructuring Transaction”), the Company determined there was an indication of impairment as at March 31,

2016. The Company performed a test of impairment and based on the result of the test, recorded an impairment charge of $666.7

million as of March 31, 2016. Key assumptions used to determine the recoverable amounts as of March 31, 2016 included:

During the second quarter 2016, no indication of impairments was identified and as such the Company did not perform a test of

impairment. However, as a result of the Company’s limited ability to fund future exploration and evaluation assets, an expense

of $22.8 million was recognized in respect of minimum required exploration costs incurred.

During the third quarter 2016, the Company identified indication of impairment in two oil and gas producing CGUs, due to an

internal change in reserve estimation in the North Colombia CGU, and a change in operating cost and cash flow assumptions

related to the Peru CGU to reflect ongoing pipeline downtimes. The Company performed a test of impairment for these CGUs

and recorded an impairment charge for oil and gas properties of $172.4 million in the North Colombia CGU and $44 million in

the Peru CGU. The fair value of the CGUs was determined using significant unobservable (Level 3) inputs as noted below.

After-tax discount rate (before-tax

rate)

Prices per barrel for 2016-2020 and

afterFuture productions

Strip pricing

11% (19%) $46 to $53 and 2% inflated after 2020 Proved developed reserves

CGU After-tax discount rate (before-tax rate) Prices per barrel for 2016-2020 and after Future productions

Reserve evaluators forecast

$51 to $71 and 2% inflated after 2020

Reserve evaluators forecast

$51 to $71 and 2% inflated after 2020

North Colombia 11% (17%) Proved developed reserves

Peru 11% (15%) Proved developed reserves

PACIFIC E&P


41

During the third quarter of 2016, the Company also identified indicators of impairment in two separate CGUs as part of oil and

gas properties related to infrastructure assets (power transmission and water irrigation). The factors giving rise to impairment

were evidence of a decline in the value of the assets as a result of a third party valuation and adverse changes in the expected

profitability of the assets. The Company performed a test for recoverability for these CGUs and recorded an impairment charge

for oil and gas properties of $64.9 million as of September 30, 2016 in the Colombia segment. Assumptions used to determine

the recoverable amounts included:

• Current disposal value or net cash flows associated with potential long-term contracts.

• Third party valuation of the power transmission asset.

As at December 31, 2016, the Company identified several indications that impairment losses previously recorded may have

decreased, including:

• The net present value of the proved and probable reserves as indicated in the Company’s certified reserve reports as of

December 31, 2016 was higher than the carrying amount of the oil and gas assets.

• The successful completion of the Restructuring Transaction significantly reduced the Company’s long-term debt and

the uncertainty with respect to the Company’s ability to continue as a going concern and finance its near-term capital

programs.

The Company updated the estimation of the recoverable amounts primarily based on the parameters used in the certified reserve

reports. The key assumptions used in the estimation included:

(1)Base reference price on ICE BRENT

Based on the recoverable amounts estimated, the Company recorded a reversal of impairment in the following CGUs:

• Central Colombia: $605 million

• North Colombia: $9 million

In addition, during the year ended in December 31, 2016, the Company commenced a plan for selling 100% of its interest in

certain assets (Refer to Note 14). Assessing the fair value of those assets, the Company reversed the following impairment charges

previously recognized: exploration and evaluation assets by $20.6 million and the Peru CGU by $17.9 million.

The recoverable amounts of the CGUs are as follows: North Colombia $122 million (December 31, 2015: $320 million); Central

Colombia CGU: $115 million (December 31, 2015: $1,237 million); South Colombia CGU: nil (December 31, 2015: nil); Peru

CGU: $72 million (December 31, 2015: $170 million).

The key assumptions used in the impairment tests to determine the recoverable amounts as of December 31, 2015 were:

(1)Base reference price on WTI

CGU After-tax discount rate (before-tax rate) Prices per barrel for 2017-2021 and after(1) Future productions

Reserve evaluator forecast

$55 to $74.6 and 2% inflated after 2021

Reserve evaluator forecast Proved and probable reserves


Reserve evaluator forecast Proved and probable reserves


Central Colombia 18% (30%) Proved and probable reserves

North Colombia 18% (30%)

South Colombia 18% (30%)

After-tax discount rate (before-tax

rate)

Prices per barrel for 2016-2020 and

after(1) Future productions

Reserve evaluator forecast

18% (23% before tax) $41 to $71 and 2% inflated after 2020 Proved and probable reserves

PACIFIC E&P


42

The table below summarizes the net impairment charges for the year ended December 31, 2016:

(1) Includes reversal of impairment previously recorded: Central Colombia CGU by $605 million; North Colombia CGU by $9 million; Peru by $17.9 million; and exploration and evaluation assets by $29.6 million.

The impairments recorded excluding goodwill may be reversed, in whole or in part, if and when the recoverable amount of the

assets and CGUs increases in future periods.

In addition to impairment charges for oil and gas properties, the Company also recorded impairment charges for other assets.

Total impairment of properties and other assets is summarized below:

2016 (1) 2015


North Colombia CGU 163,400$ 167,642$

Central Colombia CGU (123,575) 1,564,759

South Colombia CGU 11,000 238,426

Peru 96,599 323,660

Power line transmission 58,105 -

Water treatment plant 32,863 50,100

Oil and gas properties 238,392$ 2,344,587$

Plant and equipment

Colombia 30,498$ -$

Panama 3,067 -

Plant and equipment 33,565$ -$

Exploration and evaluation assets

Colombia (4,874)$ 1,242,551$

Belize 664 18,890

Peru 20,610 277,222

Brazil 5,883 421,120

Papua New Guinea - 13,000

Other 19 86,186

Exploration and evaluation assets 22,302$ 2,058,969$

Goodwill allocated to Colombia - 237,009

Total 294,259$ 4,640,565$


Note 2016 2015

Impairment of oil & gas properties and plant and equipment 271,957$ 2,344,587$

Impairment of exploration and evaluation assets 22,302 2,058,969

Impairment of other assets

Advances 20 19,268 -

Long-term recoverable VAT 20 59,601 -

Bicentenario prepayments 20 87,278 -

Investments and long-term receivables - 18,615

Other 16,599 30,749

Exploration expenses - 217,280

Impairment of goodwill - 237,009

Total impairment and exploration expenses 477,005$ 4,907,209$


PACIFIC E&P


43

Other Exploration Expenses

During the year ended December 31, 2015, through its subsidiary CGX, the Company incurred a $23.3 million fee for the

termination of an offshore exploratory drilling contract.

Also during the year ended December 31, 2015, the Company decided to withdraw from its participation in the exploratory

blocks in Papua New Guinea. As a result, the Company recorded a charge of $114.7 million as exploration expense for the year

ended December 31, 2015.

22. Interest-Bearing Loans and Borrowings

Plan Sponsor DIP Notes, Creditor DIP Notes, and Warrants

On June 22, 2016 the Company closed the $500 million DIP Financing as part of the Restructuring Transaction (Note 1), which

carried an interest rate of 12% per annum due monthly and matured on November 2, 2016, upon completion of the Restructuring

Transaction.

• $250 million of the DIP Financing were purchased by Catalyst as Plan Sponsor of the Restructuring Transaction (Note

1), which upon implementation of the plan of arrangement were converted into 29.3% of the shares of the reorganized

common stock. The Plan Sponsor DIP Notes were purchased by Catalyst at a 4% discount ($10 million) for $240 million

in cash.

• $250 million of the DIP Financing was purchased by the Funding Creditors (Note 1), and the Creditor DIP Notes upon

implementation of the plan of arrangement were amended and restated as the Exit Notes.

• In addition, the Company issued 6,250,000 Warrants to the holders of the Creditor DIP Notes, which were automatically

exercised into 12.5% of the reorganized common shares upon implementation of the plan of arrangement set out by the

Restructuring Transaction (Note 1). The exercise price of each warrant was $0.0001 and each warrant was exercised

into 100,000 common shares. The Creditor DIP Notes and the Warrants were issued for $240 million in cash.

Secured Senior Notes (Exit Notes)

On November 2, 2016, the Company in accordance with the successful completion of the Restructuring Transaction amended

and restated the terms of the Creditor DIP Notes as $250 million of secured senior notes that are due November 2, 2021 with

interest payable monthly in arrears at a rate of 10% (“Secured Senior Notes”). The Secured Senior Notes carry a payment-in-kind

(“PIK”) feature should the Company’s operating cash balance fall below $150 million, in which case the Company may elect to

pay the interest in PIK notes at an interest rate of 14% per annum. The Exit Notes are secured by a first-priority interest over

present and future property and assets of the Company, with the exception of those associated with the infrastructure subsidiaries

Pacific Midstream Ltd and Pacific Infrastructure Ventures Inc.

Maturity Principal Currency Interest Rate 2016 2015

Senior Notes - 2011 December 12, 2021 690,549$ USD 7.25% -$ 690,549$

Senior Notes - March 2013 March 28, 2023 1,000,000 USD 5.13% - 1,000,000

Senior Notes - November 2013 November 26, 2019 1,300,000 USD 5.38% - 1,300,000

Senior Notes - September 2014 January 16, 2025 1,113,651 USD 5.63% - 1,113,651

Other debt Various 2016 to 2018 215,440 USD Various - 273,146

Revolving credit facility 2017 1,000,000 USD LIBOR + 3.5% - 1,000,000

Secured Senior Notes (Exit Notes) 2021 250,000 USD 12% 250,000 -

5,569,640$ 250,000$ 5,377,346$

Current portion -$ 5,377,346$

Non-current portion 250,000 -

250,000$ 5,377,346$

As at December 31

PACIFIC E&P


44

The Exit Notes are listed on the Official List of the Luxembourg Stock Exchange and trade on the Euro MTF. Under the terms

of the notes, the Company may not incur any additional indebtedness prior to November 2, 2018. Following this date, the

Company is required to maintain (1) an interest coverage ratio of greater than 3.25:1 and (2) a debt to EBITDA ratio of greater

than 2.5:1, or would otherwise continue to be restricted from incurring additional indebtedness.

Senior Notes and Other Debts

In accordance with the Restructuring Transaction, the following interest-bearing loans and borrowings ceased to accrue interest

as at April 27, 2016. On November 2, 2016, upon the successful implementation of the Restructuring Transaction, the Senior

Notes and Other Debts of the Company were fully extinguished in exchange for common shares of the reorganized Company, as

described in Note 1:

• The Senior Notes with a total principal outstanding of $4.1 billion.

• The 2013 BOFA Loan of $2.9 million outstanding.

• The HSBC Facility of $212.5 million outstanding.

• The Revolving Credit Facility of $1 billion outstanding.

Letter of Credit Facility

On June 22, 2016 the Company entered into a letter of credit facility with certain existing lenders and supporting note holders as

part of the Restructuring Transaction (Note 1) (“Letter of Credit Facility”), maturing on June 22, 2018. The Letter of Credit

Facility allows the Company to renew certain letters of credit as they expire, which at the time of entering into the facility totaled

$115.5 million.

The Company pays a 5% annual interest on the Letter of Credit Facility. As of December 31, 2016, letters of credit totaling

$111.7 million are outstanding under the Letter of Credit Facility.

The following table summarizes the main components of finance cost for the year:

23. Finance Lease

The Company has entered into a power generation arrangement to supply electricity for one of its oil fields in Colombia until

August 2021. In addition, the Company has leased IT equipment and another power generation arrangement (Rubiales and Piriri

fields) that were accounted as finance leases. These finance leases have an average effective interest rate of 14.39% (2015:

14.52%). The Company’s minimum lease payments are as follows:

2016 2015

Interest on Senior Notes 76,599$ 217,085$

Interest on other debt 21,486 53,062

Interest on DIP Notes 21,666 -

Interest on Secured Senior Notes (Exit Notes) 4,028 -

Accretion of deferred transaction costs 20,003 14,568

Accretion of asset retirement obligations 10,261 10,185

Interest income (7,973) (21,354)

Discount arising from reclassification of short-term receivable to long-term 25,366 7,731

Acceleration of deferred transaction costs and discount - 145,229

Other 19,809 8,340

191,245$ 434,846$


PACIFIC E&P


45

For the year ending December 31, 2016, an interest expense of $3.9 million (2015: $6.1 million) was incurred on these finance

leases.

24. Asset Retirement Obligation

The Company makes full provision for the future cost of decommissioning oil production facilities on a discounted basis upon

the installation of those facilities.

The asset retirement obligation represents the present value of decommissioning and environmental liabilities costs relating to oil

and gas properties, of which up to $309 million are expected to be incurred (December 31, 2015: $345 million). Cash flows are

expected to occur in a variety of countries and currencies, and the discount rates and inflation rates are chosen in association with

the currencies in which the liabilities are expected to be settled. The future decommissioning costs and environmental liabilities

are discounted using a risk-free rate between 2.95% and 4.40%; and an inflation rate of 2.5% for cash flows expected to be settled

in U.S.$; and a risk-free rate between 6.17% and 7.93%; and an inflation rate between 2.99% and 4.1% for cash flows expected

to be settled in COP (December 31, 2015: U.S.$ risk-free -rate of 3.52%-4.97% with inflation of 0.6%, COP risk-free-rate 6.01%-

10.20% with inflation of 3.00%-5.20%) to arrive at the present value. Assumptions based on the current economic environment

have been made which management believe are a reasonable basis upon which to estimate future liability. These estimates are

reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will

ultimately depend on future market prices for the necessary decommissioning expenditures, which will reflect market conditions

at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at

economically viable rates. This in turn will depend on future oil and gas prices, which are inherently uncertain.

2016 2015

Within 1 year 6,777$ 17,473$

Year 2 6,778 6,787

Year 3 6,778 6,778

Year 4 6,797 6,778

Year 5 4,514 6,797

Thereafter - 4,514

Total minimum lease payments 31,644$ 49,127$

Amounts representing interest (8,702) (12,616)

Present value of net minimum lease payments 22,942$ 36,511$

Current portion 3,713$ 13,559$

Non-current portion 19,229 22,952

Total obligations under finance lease 22,942$ 36,511$

As at December 31

Amount

As at December 31, 2014 257,797$

Accretion expense 10,185

Disposal (4,556)

Expenditure (878)

Foreign exchange (41,810)

Changes during the year (10,141)

As at December 31, 2015 210,597$

Accretion expense 10,261

Uses (2,447)

Foreign exchange 7,637

Changes during the year 22,584

As at December 31, 2016 248,632$

Current portion 2,834$

Non-current portion 245,798

248,632$

PACIFIC E&P


46

25. Contingencies and Commitments

A summary of the Company’s commitments, undiscounted and by calendar year, is presented below:

The Company has various guarantees in place in the normal course of business. As at December 31, 2016 the Company has issued

letters of credit and guarantees for exploration and operational commitments for a total of $163 million (December 31, 2015:

$272 million). In addition, on December 14, 2016 the Company granted a pledge (security interest) in favour of Talisman

Colombia Oil & Gas Ltd. (“TCOG”) over 50% of the production (after royalties, ANH economic rights, other applicable

discounts) of CPE-6 Block in Colombia up to $48 million. The aforementioned is related with the Company’s acquisition of

TCOG’s 50% working interest in CPE-6 Block.

The Company has an assignment agreement with Transporte Incorporado S.A.S. (“Transporte Incorporado”), a Colombian

company owned by an unrelated international private equity fund. Transporte Incorporado owns a 5% capacity right in the

OCENSA pipeline in Colombia. Under the assignment agreement, the Company is entitled to use Transporte Incorporado’s

capacity to transport crude oil through the OCENSA pipeline for a set monthly premium until 2024. Pursuant to the assignment

agreement, the Company is required for the duration of the agreement to maintain a minimum credit rating of Ba3 (Moody’s) ,

which was breached in September and December 2015 and January 2016 when Moody’s downgraded the Company’s credit

rating to B3, Caa3, and C, respectively. As a result of the downgrade and in accordance with the assignment agreement, upon

giving notice to the Company, Transporte Incorporado would have the right to early-terminate the assignment agreement, and

the Company would be required to pay an amount determined in accordance with the agreement, estimated at $102.8 million.

The Company did not receive such notice from Transporte Incorporado, and on January 6, 2016 the Company received a waiver

from Transporte Incorporado of its right to early-terminate for a period of 45 days until February 15, 2016, which was further

extended several times to March 31, 2019. The Company continues to pay monthly premiums and is currently in negotiation with

Transporte Incorporado regarding the terms of the agreement and the minimum credit rating requirement. No provision has been

recognized as at December 31, 2016 relating to the breach of the credit rating requirement.

In Colombia, the Company is participating in a project to expand the OCENSA pipeline, which is expected to be completed and

commence operation in May 2017. As part of the expansion project, the Company, through its subsidiaries Meta Petroleum and

Petrominerales Colombia, entered into separate crude oil transport agreements with OCENSA for future transport capacity. The

Company will start paying ship-or-pay fees once the expansion project is complete and operational. As part of the transport

agreements, the Company is required to maintain minimum credit ratings of BB- (Fitch) and Ba3 (Moody’s). This covenant was

breached in September and December 2015 and January 2016 when Moody’s downgraded the Company’s credit rating to B3,

Caa3, and C, respectively. As a result of the downgrades and pursuant to the transport agreements, upon giving notice to the

Company, OCENSA has the right to require the Company to provide a letter of credit or proof of sufficient equity or working

capital within a cure period of 60 days starting from the day the notice is received by the Company. On November 5, 2015, the

Company received a waiver from OCENSA of its rights to receive a letter of credit which will expire once the project is complete

and operational. No provision has been recognized as at December 31, 2016 relating to the breach of the credit rating requirement.

Contingencies

The Company is involved in various claims and litigation arising in the normal course of business. Because the outcome of these

matters is uncertain, there can be no assurance that such matters will be resolved in the Company’s favour. The Company does

not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other

As at December 31, 2016 2017 2018 2019 2020 2021Subsequent to

2022Total

ODL Take-or-Pay Agreement 50,155$ 48,563$ 47,439$ 29,140$ 1,145$ -$ 176,442$

Minimum work commitments 85,037 72,716 127,143 23,386 - - 308,282

Bicentenario Ship-or-Pay Agreement 154,910 154,910 154,910 154,910 154,910 389,701 1,164,251

Operating purchase and leases 31,500 4,990 4,964 4,964 4,959 9,141 60,518

Transportation and processing commitments 221,979 209,635 211,926 211,926 211,969 719,430 1,786,865

Community obligations 9,726 - - - - - 9,726

Total 553,307$ 490,814$ 546,382$ 424,326$ 372,983$ 1,118,272$ 3,506,084$

PACIFIC E&P


47

matters – or any amount which it may be required to pay by reason thereof – would have a material impact on its financial

position, results of operations, or cash flows.

Tax Review in Colombia

The Colombian tax authority (“DIAN”) is reviewing certain income tax deductions with respect to the special tax benefit for

qualifying petroleum assets as well as other exploration expenditures. As at December 31, 2016, the DIAN has reassessed $56.5

million of tax owing, including estimated interest and penalties, with respect to the denied deductions.

As at December 31, 2016, the Company believes that disagreements with the DIAN related to the denied income tax deductions

will be resolved in favour of the Company. No provision with respect to income tax deductions under dispute has been recognized

in the consolidated financial statements.

High Price Royalty in Colombia

The Company has certain exploration contracts acquired through business acquisitions where there existed outstanding

disagreements with the Agencia Nacional de Hidrocarburos (National Hydrocarbon Agency or “ANH” of Colombia) relating to

the interpretation of the high-price participation clause. These contracts require high-price participation payments to be paid to

the ANH once an exploitation area within a contracted area has cumulatively produced 5 million or more barrels of oil. The

disagreement involves whether the exploitation areas under these contracts should be determined individually or combined with

other exploration areas within the same contracted area, for the purpose of determining the 5 million barrel threshold. The ANH

has interpreted that the high-price participation should be calculated on a combined basis.

The Company disagrees with the ANH’s interpretation and asserts that in accordance with the exploration contracts, the 5 million

barrel threshold should be applied on each of the exploitation areas within a contracted area. The Company has several contracts

that are subject to ANH high-price participation. One of these contracts is the Corcel Block, which was acquired as part of the

Petrominerales acquisition, and which is the only one for which an arbitration process has been initiated. However, the arbitration

process for Corcel was under suspension at the time the Company acquired Petrominerales. As at December 31, 2016, the amount

under arbitration is approximately $195 million plus related interest of $45 million. The Company also disagrees with the interest

rate that the ANH has used in calculating the interest cost. The Company asserts that since the high-price participation is

denominated in the U.S. dollar, the contract requires the interest rate to be three-month LIBOR + 4%, whereas the ANH has

applied the highest legally authorized interest rate on Colombian peso liabilities, which is over 20%. An amount under discussion

with the ANH for another contract is approximately $99 million plus interest.

The Company and the ANH are currently in discussion to further understand the differences in interpretation of these exploration

contracts. The Company believes that it has a strong position with respect to the high-price participation based on legal

interpretation of the contracts and technical data available. However, in accordance with IFRS 3, to account for business

acquisitions the Company is required to record and has recorded a liability for such contingencies as of the date of acquisition,

although the Company believes the disagreement will be resolved in favour of the Company. The Company does not disclose the

amount recognized as required by paragraphs 84 and 85 of IAS 37, on the grounds that this would be prejudicial to the outcome

of the dispute resolution.

26. Issued Capital

a) Authorized, issued, and fully paid common shares

The Company has an authorized capital of an unlimited number of common shares with no par value.

Continuity schedule of share capital is as follows:

PACIFIC E&P


48

Upon implementation of the Restructuring Transaction on November 2, 2016, all previously issued and outstanding common

shares of the Company, together with the common shares issued as part of the Restructuring Transaction, were consolidated on

the basis of 100,000 pre-consolidation shares to one post-consolidation share. As a result, the Company’s common shares that

were issued and outstanding prior to November 2, 2016 have been subsequently diluted. Refer to Note 1 for details on the share

capital resulting from the Restructuring Transaction.

b) Stock options

Prior to November 2, 2016, the Company had a rolling Stock Option Plan in compliance with the applicable TSX policy for

granting stock options. On November 2, 2016 upon implementation of the Restructuring Transaction (Note 1), all outstanding

stock options were duly cancelled.

c) Deferred share units

The Company established a new Deferred Share Unit Plan for its non-employee directors on November 2, 2016. Each DSU

represents the right to receive a cash payment, shares or a combination of both upon retirement or termination equal to the volume-

weighted average market price of the Company’s shares at the time of surrender. Cash dividends paid by the Company are

credited as additional DSUs. The fair value of the DSUs granted and the changes in their fair value during the period were

recognized as share-based compensation on the Consolidated Statement of Income (Loss), with a corresponding amount recorded

in accounts payable and accrued liabilities on the Consolidated Statement of Financial Position.

The Company’s previous deferred share unit plan that was for non-employee directors and employees entitled the holder to a

cash payment on retirement or termination equal to the volume-weight average market price of the Company’s shares at the time

of surrender. As a result of satisfying all the terms of the Restructuring Transaction (Note 1), all deferred share units under this

plan were cancelled on November 2, 2016.

The December 31, 2016 liability is based on a fair value of $42.74 per DSU approximating the Company’s share price in U.S

dollars (December 31, 2015: $1.71).

Number of Shares Amount

As at December 31, 2014 313,255,053 2,610,485$

Treasury shares issued 1,766,145 5,303

As at December 31, 2015 315,021,198 2,615,788$

Issued on completion of the Restructuring Transaction 5,000,000,000,000 2,129,567

Share consolidation (5,000,265,018,835) -

As at December 31, 2016 50,002,363 4,745,355$

Number of options

outstanding

Weighted average

exercise price (C$)

As at December 31, 2014 23,168,792 21.86

Cancelled and expired during the year (6,647,675) 17.16

As at December 31, 2015 16,521,117 23.76

Cancelled and expired during the year (16,521,117) 23.76

As at December 31, 2016 - -

Number of DSUs

outstanding Amount

As at December 31, 2014 2,487,386 17,075$

Fair value adjustment for the year - (19,747)

Granted during the year 6,611,178 17,902

Settled during the year (2,218,139) (6,730)

As at December 31, 2015 6,880,425 8,500$

Fair value adjustment for the year - (8,862)

Cancelled during the year (8,656,468) -

Granted during the year 1,899,955 1,420

Settled during the year (107,278) (95)

Foreign exchange translation - (235)

As at December 31, 2016 16,634 728$

PACIFIC E&P


49

For the year ended December 31, 2016, $7.8 million of gain (2015: $1.6 million gain) were recorded as share-based compensation

expenses with respect to DSUs granted during the period and the change in fair value.

27. Related-party Transactions

The following sets out the details of the Company’s related party transactions:

a) The Company has take-or-pay contracts with ODL for the transportation of crude oil from the Company’s fields to

Colombia’s oil transportation system for a total commitment of $176 million from 2017 to 2020. During the year ended

December 31, 2016 the Company paid $89.5 million to ODL (2015: $108.5 million) for crude oil transport services under

the pipeline take-or-pay agreement and had accounts payable of $0.3 million (December 31, 2015: $13.1 million). In

addition, the Company received $0.3 million from ODL during the year ended December 31, 2016 (2015: $2.9 million) with

respect to certain administrative services and rental equipment and machinery. The Company had accounts receivable of

$0.6 million from ODL as at December 31, 2016 (December 31, 2015: $0.1 million). The Company has an indirect interest

of approximately 22% in ODL.

b) The Company has ship-or-pay contracts with Bicentenario for the transportation of crude oil from the Company’s fields to

Colombia’s oil transportation system for a total commitment of $1.1 billion from 2017 to 2025. The Bicentenario pipeline

has experienced periodic suspensions following security-related disruptions. During the year ended December 31, 2016, the

Company paid $168.9 million to Oleoducto Bicentenario de Colombia S.A.S. (2015: $155.6 million), a pipeline company

in which the Company has a 43% interest, for crude oil transport services under the pipeline ship-or-pay agreement. During

the year ended December 31, 2016, the Company recognized nil in interest income from Bicentenario on a shareholder loan

that has since been repaid (2015: $1.3 million). The Company had an advance of $87.9 million as at December 31, 2016

(December 31, 2015: $87.9 million) to Bicentenario as a prepayment of transport tariff, which is to be amortized against

future barrels transported above the Company’s contract capacity (see Note 20). As at December 31, 2016, the Company

had trade accounts receivable of $13.4 million (December 31, 2015: $0.4 million) from Bicentenario.

c) As at December 31, 2016, the Company had loans receivable from PII in the amount of $72.4 million (December 31, 2015:

$72.4 million). The loans are guaranteed by PII’s pipeline project and bear interest that ranges from LIBOR + 2% to 7% per

annum. The Company owns 41.77% of PII (December 31, 2015: 41.79%). Interest income of nil was recognized during the

year ended December 31, 2016 (2015: $5 million) regarding the loan. In addition, during the year ended December 31, 2016,

the Company received $2.7 million (2015: $3.7 million) from PII with respect to contract fees for advisory services and

technical assistance in pipeline construction for “Oleoducto del Caribe.” In addition, as at December 31, 2016, the Company

had accounts receivable of $0.8 million (December 31, 2015: $0.5 million) from a branch of PII. As at December 31, 2016,

the Company had accounts payable of $0.9 million to PII (December 31, 2015: $0.5 million).

In December 2012, the Company entered into a take-or-pay agreement with Sociedad Puerto Bahia S.A., a company that is

wholly owned by PII. Pursuant to the terms of the agreement, Sociedad Puerto Bahia S.A. will provide for the storage,

transfer, loading, and unloading of hydrocarbons at its port facilities. The contract term commenced in 2014 and will

continue for seven years, renewable in one-year increments thereafter. During the year ended December 31, 2016, the

Company paid $39.4 million to Sociedad Puerto Bahia S.A. (2015: $28.6 million) for storage, transfer, and loading and

unloading of hydrocarbons. These agreements may indirectly benefit the other shareholders of PII, including Blue Pacific

Assets Corp. (“Blue Pacific”) and other unrelated parties. Three former directors and one former executive officer, control

or provide investment advice to the holders of 88% of the shares of Blue Pacific.

During the year ended December 31, 2016, the Company paid nil in advances to Sociedad Puerto Bahía S.A. in relation to

services received (2015: $28.6 million, of which $10.9 million was expensed during the year ended December 31, 2015).

d) On February 29, 2016, the Company agreed to provide CGX with a bridge loan of up to $2 million at an interest rate of 5%

per annum, payable within 12 months of the first draw down. As at December 31, 2016, the amount CGX had drawn down

from the bridge loan was $2 million, and the Company considers this loan to be fully impaired. Subsequently, on October

13, 2016, the Company agreed to provide CGX with an additional bridge loan of up to $2 million at an interest rate of 5%

PACIFIC E&P


50

per annum and payable within 12 months of the first draw down. As at December 31, 2016, CGX had drawn down $1

million, and the Company considers this loan to be fully impaired.

In October 2014, the Company extended a bridge loan to CGX of C$7.5 million with an interest rate of 5%, and as at

December 31, 2016 the full amount is still outstanding and fully impaired. In addition, in November 2015, CGX issued

convertible debentures to the Company in an amount of $1.5 million with a conversion price of C$0.335, and as at December

31, 2016 the Company has not converted the debentures.

e) In October 2012, the Company and Ecopetrol signed two Build, Own, Manage, and Transfer (“BOMT”) agreements with

Consorcio Genser Power-Proelectrica and its subsidiaries (“Genser-Proelectrica”) to acquire certain power generation

assets for the Rubiales field. Genser-Proelectrica is a joint venture between Proelectrica, in which the Company has a 21.1%

indirect interest and Genser Power Inc. (“Genser”) which is 51% owned by Interamerican. On March 1, 2013, these

contracts were assigned to TermoMorichal SAS (“TermoMorichal”), the company created to perform the agreements, in

which Interamerican has a 51% indirect interest. Total commitment under the BOMT agreements is $229.7 million over 10

years. In April 2013, the Company and Ecopetrol entered into another agreement with Genser-Proelectrica to acquire

additional assets for a total commitment of $57 million over 10 years. At the end of the Rubiales Association Contract on

June 30, 2016, the Company’s obligations along with the power generation assets were transferred to Ecopetrol. As at

December 31, 2016, the Company did not have any advance to Genser-Proelectrica (December 31, 2015: $3.3 million).

During the year ended December 31, 2016, the Company made payments of $20.2 million relating to power generation cost

(2015: $30.6 million). The Company had accounts payable of $0.6 million (December 31, 2015: $3.6 million) due to Genser-

Proelectrica as at December 31, 2016. In addition, on May 5, 2014, a subsidiary of the Company provided a guarantee in

favour of XM Compañia de Expertos en Mercados S.A. on behalf of Proelectrica, guaranteeing obligations pursuant to an

energy supply agreement in the aggregate amount of approximately $16.7 million aligned with the Company’s participation.

In December 2014 the Company entered into a new contract with Genser-Proelectrica related to the operation and

maintenance of the power generation facility located in the Sabanero field.

In October 2013, the Company entered into connection agreements and energy supply agreements with Proelectrica for the

supply of power to the oil fields in the Llanos basin. The connection agreements authorize Meta Petroleum Corp. and Agro

Cascada S.A.S. to use the connection assets of Petroelectrica for power supply at the Quifa and Rubiales fields. The

agreement commenced on November 1, 2013, and will operate for 13 years. During the year ended December 31, 2016, the

Company made payments of $17.2 million (2015: $46.3 million) under this agreement.

The Company has entered into several take-or-pay agreements as well as interruptible gas sales and transport agreements to

supply gas from the La Creciente natural gas field to Proelectrica’s gas-fired plant. During the year ended December 31,

2016, the Company recorded revenues of $8.7 million (2015: $9.3 million) from such agreements. As at December 31, 2016,

the Company had trade accounts receivable of $0.2 million (December 31, 2015: $12.3 million) from Proelectrica.

Under the energy supply agreements, Proelectrica provides electricity to the Company for power supply at the Quifa and

Rubiales fields with payments to be calculated monthly on a demand-and-deliver basis. The term of the agreement is until

December 31, 2026. The aggregate estimated energy supply agreement is for 1.5 million kilowatts.

f) Revenue from Proelectrica in the normal course of the Company’s business was $8.7 million for the year ended December

31, 2016 (2015: $9.3 million). Blue Pacific owns a 5% interest in Proelectrica. The Company and Blue Pacific’s indirect

interests are held through Interamerican.

g) On December 11, 2015 the Company and the other shareholders of Interamerican, including Proenergy Corp. (a subsidiary

of Blue Pacific), entered into a share purchase agreement with Faustia Development S.A., Tusca Equities Inc., and

Associated Ventures Corp. (the “Interamerican Purchasers”) for the sale of 70% of the shares of Interamerican. As part

of the transaction, the Company agreed to sell 4% of the Company’s 24.9% equity interest in Interamerican to the

Interamerican Purchasers for approximately $5 million. As a result of the sale, the Company currently owns 21.09% and

Proenergy Corp. (Blue Pacific) currently owns approximately 5% of Interamerican. Associated Ventures Corp. was

controlled by a former director of the Company who resigned on April 27, 2016.

PACIFIC E&P


51

h) The Company has previously established two charitable foundations in Colombia: the Paye Foundation (“Paye,” formerly

the Pacific Rubiales Foundation) and the Foundation for Social Development of Energy Available (“FUDES”). FUDES

was liquidated on September 28, 2016 and all pending obligations and commitments were assigned to Paye, which finalized

its investment activities on December 31, 2016. Both foundations had the objective of advancing social and community

development projects in the country. During the year ended December 31, 2016, the Company contributed $9.6 million to

these foundations (2015: $15.3 million). At as December 31, 2016, the Company had accounts receivable (advances) of nil

(December 31, 2015: $0.4 million) and accounts payable of $1.7 million (December 31, 2015: $3.2 million). An officer of

the Company sits on the board of directors of Paye.

The Company’s key management personnel include its Board of Directors and the executive officers.

The Company also had the following transactions with parties who were related to or officers of the Company at the time they

were entered into, but who were no longer officers of the Company as of December 31, 2016.

a) As at December 31, 2016, interest free loans receivable from former directors and officers have been fully repaid (December

31, 2015: $0.5 million outstanding).

In August 2015, the Company agreed to pay $8.3 million in severance to one of its officers, who retired from the Company

effective August 14, 2015. The severance included $5.5 million in cash paid during 2015, $1.4 million paid in the three

months ended March 31, 2016, and $1.4 million settled in new common shares of the Company as part of the Restructuring

Transaction. In addition, the departing officer’s DSU entitlement was paid in kind effective August 14, 2015 with the

Company’s shares held in treasury for a total of approximately 1.3 million common shares. Also during 2015, the Company

made payments in kind of approximately 0.5 million common shares to 3 departing directors as settlement for DSU

entitlements.

b) As of December 31, 2016 the Company had accounts payable of $1.9 million (December 31, 2015: $1.9 million) outstanding

to Pacific Green with respect to contributions made previously by Pacific Green to Promotora Agricola, an agricultural

project controlled by the Company. Pacific Green’s contributions to the project are expected to be capitalized in the near

term. Pacific Green was controlled by three former officers of the Company who retired in November 2016.

28. Financial Assets and Liabilities

Overview of Risk Management

The Company explores, develops, and produces oil and gas and enters into contracts to sell its oil and gas production and to

manage its market risk associated with commodity markets, and notably its exposure to oil pricing. The Company also enters into

supply agreements and purchases goods and services denominated in non-functional currencies such as Colombian Pesos for its

Colombian-based activities. These activities expose the Company to market risk from changes in commodity prices, foreign

exchange rates, interest rates, and credit and liquidity risks that affect the Company’s earnings and the value of associated financial

instruments it holds.

The Company seeks to minimize the effects of these risks by using derivative financial instruments to hedge its risk exposures.

The Company’s strategy, policies and controls are designed to ensure that the risks it assumes comply with the Company’s

internal objectives and its risk tolerance. It is the Company’s policy that no speculative trading in derivatives shall be undertaken.

2016 2015

Short-term employee benefits 26,610$ 20,521$

Termination benefits 20,603 -

Post-employment pension and medical benefits 3,295 1,437

Share-based payments 1,571 16,228

52,079$ 38,186$

As at December 31

PACIFIC E&P


52

When possible and cost effective, the Company applies hedge accounting. Hedging does not guard against all risks and is not

always effective. The Company could recognize financial losses as a result of volatility in the market values of these contracts.

Risks Associated with Financial Assets and Liabilities

a) Market Risks

Commodity Price Risk

Commodity price risk is the risk that the cash flows and operations of the Company will fluctuate as a result of changes in

commodity prices associated with oil pricing. Significant changes in commodity prices can also impact the Company’s ability to

raise capital or obtain additional debt financing. Commodity prices for crude oil are impacted by world economic events that

dictate the levels of supply and demand. While the Company does not engage in speculative financial instrument trading, it may

enter into various hedging strategies such as costless collars, swaps, and forwards to minimize its commodity price risk exposure

to oil pricing.

Foreign Currency Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the

Company’s financial assets or liabilities. As the Company operates primarily in Colombia, fluctuations in the exchange rate

between the Colombian peso and the U.S. dollar can have a significant effect on the Company’s reported results.

To mitigate the exposure to the fluctuating COP/U.S.$ exchange rate associated with operating and general and administrative

expenses incurred in COP, the Company may enter into various hedging strategies such as currency costless collars, swaps and

forwards. In addition, the Company may also enter into currency derivatives to manage the foreign exchange risk on financial

assets that are denominated in the Canadian dollar.

The Company’s foreign exchange gain/loss primarily includes unrealized foreign exchange gains and losses on the translation of

COP-denominated risk management assets and liabilities held in Colombia.

Interest Rate Risk

The Company does not have any financial liability that is subject to interest rate risk as of December 31, 2016.

Sensitivity Analysis on Market Risks

The details below summarize the sensitivities of the Company’s risk management positions to fluctuations in the underlying

benchmark prices, with all other variables held constant. Fluctuations in the underlying benchmark could have resulted in

unrealized gains or losses impacting pre-tax net earnings as follows:

• A 10% change in the COP/U.S.$ exchange rate would have resulted in a $1 million change in foreign exchange gain/loss

as at December 31, 2015 (2015: $13.4 million).

b) 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

obligations in accordance with agreed terms. The Company actively limits the total exposure to individual client counterparties

and holds a trade credit insurance policy for indemnification for losses from non-collection of trade receivables.

PACIFIC E&P


53

As at December 31, 2016, three of the Company’s customers had accounts receivable that were greater than 10% of the total

trade accounts receivable. The Company’s credit exposure to these customers was $46 million, $25 million and $16 million (see

“QV Trading Litigation” below) or 44%, 23%, and 15% of trade accounts receivable, respectively (December 31, 2015: one

customer at $39 million or 23% of trade accounts receivable). Revenues from these customers for 2016 were $245 million, $147

million and nil, or 17%, 10%, and 0% of revenue (2015: $362 million or 13% of revenue), respectively.

The majority of the receivables from joint arrangements is due from Ecopetrol. During the year ended December 31, 2016, the

Company recorded impairment changes of $5 million (December 31, 2015: nil), relating to certain receivable related to joint

operations.

Included in long-term receivables as at December 31, 2016 is $56.1 million related to the Company’s exit from the Papua New

Guinea blocks ($50.1 million as at December 31, 2015). The carrying amount represents the discounted amount (12% discount

rate) that the Company is entitled to receive from the partner following the Company’s withdrawal from the blocks, and is payable

over the period from the withdrawal date in 2015 until 2021 dependent on cash flows from the blocks, with 2021 representing

the final due date for the payment. The Company is currently negotiating with the partner, which was recently acquired, to

potentially modify the terms of payment.

The Company does not hold any collateral or other credit enhancements to cover its credit risks associated with its financial

assets, except for the loan with PII.

QV Trading Litigation

The Company is in the process of commencing legal proceedings against an unrelated customer, QV Trading LLC, in respect of

an overdue accounts receivable in the amount of approximately $16 million for the sale of oil in August 2015.

c) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s

process for managing liquidity risk includes ensuring, to the extent possible, that it will have sufficient liquidity to meet its

liabilities when they become due. The Company prepares annual capital expenditure budgets that are monitored and updated as

required. In addition, the Company requires authorizations for expenditures on projects to assist with the management of capital.

As at December 31, 2016, the Company had $163 million of letters of credit outstanding, $111.7 million of which are committed

under the Letter of Credit Facility (Note 22).

The following are the contractual maturities of non-derivative financial liabilities (based on calendar year and undiscounted):

Note 2016 2015

Trade receivable 104,994$ 173,777$

Advances / deposits 27,174 19,487

Other receivables 19,715 182,384

Receivable from joint arrangements 41,183 101,413

Allowance for doubtful accounts (16,340) (16,909)

176,726$ 460,152$

Long-term receivables 20 105,460 60,469

282,186$ 520,621$

As at December 31

Financial liability due in Note 2017 2018 2019 2020 2021 Total

Accounts payable and accrued liabilities 576,350$ -$ -$ -$ -$ 576,350$

Secured Senior Notes (Exit Notes) 22 - - - - 250,000 250,000

Obligations under finance lease 23 6,777 6,778 6,778 6,797 4,514 31,644

Total 583,127$ 6,778$ 6,778$ 6,797$ 254,514$ 857,994$

PACIFIC E&P


54

Accounts payable and accrued liabilities consisted of the following as at December 31, 2016 and 2015:

d) Hedge Accounting and Risk Management Contracts

The terms and conditions of the hedging instruments and expected settlement periods are listed below for instruments outstanding

as at the following dates:

December 31, 2016

In July 2016, the Company entered in a number of new oil price risk management contracts. The terms and conditions of the

hedging instruments and expected settlement periods as at December 31, 2016 are as follows:

During the first quarter 2016, all of the Company’s outstanding oil price derivative contracts were early terminated and a $161

million settlement was recognized, which included $128.2 million in cash received and a $33.4 million reduction to the principal

outstanding under one of the credit facilities (Bank of America). The amount previously accumulated within equity as a cash flow

hedge and time value reserve has been reclassified into net income (loss) as the original hedged transactions were contracted and

occurred between April and June 2016.

December 31, 2015

2016 2015

Trade and other payables 97,678$ 403,176$

Accrued liabilities 170,588 450,355

Payables - JV partners 13,446 11,076

Advances, warranties, and deposits 38,074 91,982

Withholding tax and provisions 256,564 260,302

576,350$ 1,216,891$

As at December 31

Type of Instrument Term Benchmark Assets Liabilities

Not Subject to Hedge Accounting:

Commodities Price Risk

Zero-cost collars March 2017 8,080,000 42.5 / 61.5 BRENT - (31,985)

Total not subject to hedge accounting -$ (31,985)$

Total December 31, 2016 -$ (31,985)$

Notional Amount /

Volume (bbl)

Floor/ Ceiling or strike

price

Carrying amount

PACIFIC E&P


55

As at December 31, 2015 it was determined that the derivatives subject to hedge accounting no longer met the requirement of

being highly probable, and therefore hedge accounting for these instruments was discontinued. The amount previously

accumulated within equity as a cash flow hedge and time value reserve was reclassified into net income as the original hedged

transactions occurred between January and June 2016.

As describe below, during the year ended December 31, 2016, the Company recorded a total of $139.5 million of unrealized

losses from derivatives that were designated as hedges and those that were not designated (2015: $129.4 million of gain).

Instruments Subject to Hedge Accounting

Hedging Relationship

The Company’s hedging strategies for which hedge accounting is applied consists of the following:

• Commodity price: The Company’s forecast sales are subject to commodity risk associated with the price of crude oil.

The Company has identified the cash flows associated with the forecast sale of specified volumes of crude oil as the

hedged item. The Company utilizes commodity price collars as designated hedging instruments to manage related

fluctuations in cash flow above or below the specified ranges.

• The Company uses statistical analysis to assess the effectiveness of the commodity hedging relationship. Potential

sources of ineffectiveness associated with the commodity hedging relationship include changes in the underlying

benchmark of the forecast crude oil sales, variations in the location and quality differentials, and the timing of pricing

of the hedged item and hedging instrument.

As at December 31, 2016, none of the Company’s outstanding financial derivative positions are subject to hedge accounting.

As at December 31, 2015:

Type of Instrument Term Benchmark Assets Liabilities

Previously Subject to Hedge Accounting:


Zero-cost collars January to June 2016 600,000 60-66 WTI 12,244 (3)

Total subject to hedge accounting 12,244$ (3)$

Not Subject to Hedge Accounting:


Zero-cost collars April to December 2016 1,800,000 48 / 68 WTI 15,360 -

Zero-cost collars January to December 2016 1,500,000 48.60 - 56 / 58.75 -73.45 BRENT 77,867 (53,061)

(counterparty option)

Extendable Various 2016 1,650,000 57-59.30 / 62-64.30 BRENT 32,728 (1)

Extendable Swap January to March 2016 2,100,000 55.20 - 55.30 BRENT 34,584 (1)

Total not subject to hedge accounting 160,539$ (53,063)$

Total December 31, 2015 172,783$ (53,066)$

Notional Amount /

Volume (bbl)

Floor/ Ceiling or strike

price

Carrying amount

Hedged Item

Line item in the statement of

financial position where the

hedging instrument is located

Changes in fair value used for

calculating hedge

ineffectiveness for 2015

Changes in fair value used for

calculating hedge

ineffectiveness for 2015

Cumulative cash flow hedge

reserve for continuing hedges

Cumulative cash flow hedge

reserve for discontinued hedges

Cash flow hedges:


Zero-cost collars Risk Management Assets 12,146$ 17,634$ -$ -$

Zero-cost collars Risk Management Liabilities - - 12,146 -

12,146$ 17,634$ 12,146$ -$

Hedging Instrument

PACIFIC E&P


56

Impact of Hedging Relationship

The Company excludes changes in fair value relating to the option time value from ineffectiveness assessments and records these

amounts in other comprehensive income, as a cost of hedging.

For the year ended December 31, 2016:

For the year ended December 31, 2015:

For the year ended December 31, 2016, the Company did not record any ineffectiveness on foreign currency risk management

contracts (2015: loss of $5.1 million).

For the year ended December 31, 2016, the Company did not record any ineffectiveness on commodity price risk management

contracts (2015: gain of $0.3 million).

Instruments Not Subject to Hedge Accounting:

As part of the Company’s risk management strategy, derivative financial instruments are used to manage exposure to risks in

addition to those designated for hedge accounting. As these instruments have not been designated as hedges, the change in fair

value is recorded in profit or loss as risk management gain or loss.

For the year ended December 31, 2016, the Company recorded risk management losses of $152 million on commodity price risk

management contracts (2015: gain of $86.7 million). In addition, during the year ended December 31, 2016, the Company

recognized in revenue a $152 million gain, related to these instruments, which were settled (2015: gain of $150.6 million).

For the year ended December 31, 2016, the Company has not recorded risk management gains or losses on foreign currency risk

management contracts in net gain (2015: gain of $42.7 million, included $91.9 million of unrealized gain, representing the change

in fair value). In addition, during the year ended December 31, 2016, the Company did not recognize realized gains or losses in

foreign exchange, which were settled (2015: $49.2 million loss).

e) Fair Value

The Company’s financial instruments are cash and cash equivalents, restricted cash, accounts receivable, accounts payable and

accrued liabilities, risk management assets and liabilities, loans and borrowings, finance lease obligations, debentures, and fair

Change in the value of the

hedging instrument recognized

in OCI gain/(loss)

Hedge ineffectiveness

recognized in profit or loss

gain/(loss)

Line item in profit or loss (that

includes hedge ineffectiveness)

Amount reclassified from the

cash flow hedge reserve to profit

or loss gain/(loss)

Line item affected in profit or

loss because of the

reclassification


Zero-cost collars - - Risk management gain (loss) 12,146 Risk management

-$ -$ 12,146$

Change in the value of the

hedging instrument recognized

in OCI gain/(loss)

Hedge ineffectiveness

recognized in profit or loss

gain/(loss)

Line item in profit or loss (that

includes hedge ineffectiveness)

Amount reclassified from the

cash flow hedge reserve to profit

or loss gain/(loss)

Line item affected in profit or

loss because of the

reclassification

Foreign exchange risk

Zero-cost collars (25,347)$ (5,138)$ Foreign exchange gain (loss) (59,325)$ Production and operating costs


Zero-cost collars 126,683 (329) Risk management gain (loss) 153,615 Revenue

101,336$ (5,467)$ 94,290$

PACIFIC E&P


57

value through other comprehensive income investments on the statement of financial position. The carrying value and fair value

of these financial instruments are disclosed below by financial instrument category.

1) Total fair value of the various Senior Notes is estimated using their last traded prices as at December 31, 2015.

The following table summarizes the Company’s financial instruments that are carried or disclosed at fair value in accordance

with the classification of fair value input hierarchy in IFRS 7 Financial Instruments - Disclosures.

Note Carrying value Fair value Carrying value Fair value

Financial Assets

Financial assets measured at amortized cost

Cash and cash equivalents 389,099$ 389,099$ 342,660$ 342,660$

Restricted cash 113,782 113,782 35,922 35,922

Accounts receivable 28b 176,726 176,726 460,152 460,152

Long-term receivables 20 105,460 105,460 60,469 60,469

785,067 785,067 899,203 899,203

Financial assets mandatorily measured at fair value through

profit or loss (FVTPL)

Held-for-trading derivatives that are not designated in hedge

accounting relationships 28d - - 160,539 160,539

- - 160,539 160,539

Financial assets designated as measured at fair value through

other comprehensive income (FVTOCI)

Investments in equity instruments 20 962 962 1,125 1,125

962 962 1,125 1,125

Derivative instruments in designated hedge accounting

relationships 28d - - 12,244 12,244

- - 12,244 12,244

786,029$ 786,029$ 1,073,111$ 1,073,111$

Financial Liabilities

Financial liabilities measured at amortized cost

Accounts payable and accrued liabilities 28c (576,350)$ (576,350)$ (1,216,891)$ (1,216,891)$

Loans and borrowings 22 - - (1,273,146) (248,745)

Secured Senior Notes (Exit Notes) 22 (250,000) (250,000) - -

Senior Notes (1)

22 - - (4,104,200) (801,870)

Obligations under finance lease 23 (22,942) (28,904) (36,511) (46,000)

(849,292) (855,254) (6,630,748) (2,313,506)

Financial liabilities measured at fair value through profit or loss

(FVTPL)

Held-for-trading derivatives that are not designated in hedge

accounting relationships 28d (31,985) (31,985) (53,063) (53,063)

(31,985) (31,985) (53,063) (53,063)

Derivative instruments in designated hedge accounting

relationships 28d - - (3) (3)

- - (3) (3)

(881,277)$ (887,239)$ (6,683,814)$ (2,366,572)$

As at December 31, 2016 As at December 31, 2015

PACIFIC E&P


58

As at December 31, 2016

As at December 31, 2015

The Company uses Level 1 inputs, being the last quoted price of the traded investments, to measure the fair value of its financial

assets at FVTOCI, with the exception of certain investments that do not have an observable market.

The Company uses Level 2 inputs to measure the fair value of its risk management contracts, certain receivables and debt

balances. The fair values of the risk management contracts are estimated using internal discounted cash flows based on forward

prices and quotes obtained from counterparties to the contracts, taking into account the creditworthiness of those counterparties

Quoted prices in

active markets

Significant

Observable Inputs

Significant

Unobservable

Inputs

Level 1 Level 2 Level 3 Total

Financial assets at FVTOCI

Investments in equity instruments -$ -$ 962$ 962$

Other Assets

Long-term receivables -$ 105,460$ -$ 105,460$

Financial liabilities at Fair Value

Held-for-trading derivatives that are not designated in hedge accounting

relationships -$ (31,985)$ -$ (31,985)$

Other liabilities

Secured Senior Notes (Exit Notes) -$ (250,000)$ -$ (250,000)$

Obligations under finance lease - (28,904) - (28,904)

Quoted prices in

active markets

Significant

Observable Inputs

Significant

Unobservable

Inputs

Level 1 Level 2 Level 3 Total

Financial assets at Fair Value


relationships -$ 160,539$ -$ 160,539$

Derivative instruments in designated hedge accounting relationships - 12,244 - 12,244

Financial assets at FVTOCI

Investments in equity instruments -$ -$ 1,125$ 1,125$

Other Assets

Long-term receivables -$ 60,469$ -$ 60,469$

Financial liabilities at Fair Value


relationships -$ (53,063)$ -$ (53,063)$

Derivative instruments in designated hedge accounting relationships - (3) - (3)

Other liabilities

Loans and borrowings -$ (248,745)$ -$ (248,745)$

Senior notes (801,870) - - (801,870)

Obligations under finance lease - (46,000) - (46,000)

PACIFIC E&P


59

or the Company’s credit rating when applicable. The fair value of certain receivables and debt balances are estimated based on

recently observed transactions.

The Company uses Level 3 inputs to measure the fair value of certain investments that do not have an active market.

Valuation Techniques

Foreign currency forward contracts are measured based on observable spot exchange rates and the yield curves of the respective

currencies, as well as the currency basis spreads between the respective currencies. The credit risks associated with the

counterparties and the Company are estimated based on observable benchmark risk spreads.

Commodity risk management contracts are measured at observable spot and forward crude oil prices.

f) Capital Management

The Company’s objectives when managing capital are: (i) to maintain a flexible capital structure, which optimizes the cost of

capital at acceptable risk; and (ii) to maintain investor, creditor and market confidence to sustain the future development of the

business.

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk

characteristics of its underlying assets. To maintain or adjust the capital structure, the Company may from time to time issue

shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels.

The Company monitors capital based on the following non-standardized IFRS measures: current and projected ratios of debt to

cash flow from operations and debt to capital employed. The Company’s objective, which is currently met, is to maintain a debt

to cash flow from operations ratio of less than three times. The ratio may increase at certain times as a result of acquisitions. To

facilitate the management of this ratio, the Company prepares annual budgets, which are updated depending on varying factors

such as general market conditions and successful capital deployment. The Company’s share capital is not subject to external

restrictions.

The Company finished the process of negotiating with its stakeholders for a restructuring of its capital structure, including its

long-term debts. Refer to Note 1.

29. Supplemental Disclosure on Cash Flows

Changes in non-cash working capital are as follows:

2016 2015

Equity attributable to equity holders of the parent 1,495,770$ (3,099,376)$

Long-term debt 250,000 -

Working capital surplus (deficit) 205,616 (5,454,675)

1,951,386$ (8,554,051)$

As at December 31

2016 2015

Decrease in accounts receivable 203,048$ 301,999$

Decrease (increase) in income taxes receivable 114,711 (51,114)

Decrease in accounts payable and accrued liabilities (463,351) (726,613)

(Increase) decrease in inventories (11,524) 578

Increase in income taxes payable 10,875 43,606

Decrease (increase) in prepaid expenses 1,894 (1,031)

(144,347)$ (432,575)$


PACIFIC E&P


60

Other cash flow information is as follows:

30. Subsequent Events

a) On January 30, 2017 the Company received Brazilian regulatory approval for the sale of its working interest in certain

Brazilian blocks to Karoon (Note 16), and on February 2, 2017 Karoon paid $15.5 million in cash in accordance with

the terms of the agreement.

b) On March 10, 2017, the Company and Amerisur Exploración Colombia Limitada (“AMERISUR”) entered into four

farm-out agreements whereby AMERISUR agreed to acquire the Company’s participation interests in four blocks in

Colombia. The total transaction price is $4.9 million, plus a royalty calculated and payable based on a percentage of the

hydrocarbons produced on two of the blocks. Each farm-out agreement is subject to Colombian regulatory approval,

and is included in assets held for sale as of December 31, 2016.

c) On March 13, 2017, the Company received Brazilian regulatory approval for the transfer of the blocks to QGEP (Note

16), with the transaction expected to be fully consummated shortly subject to the amendment of the concession

agreements.

d) On March 13, 2017, the Colombian Insolvency Judge issued a decision to terminate the proceedings under Ley 1116 of

2006. Consequently, the Company will initiate the processes to lift all liens imposed by the mentioned judge, including

the remaining $23.7 million held in the trust account on behalf of Colombian trade creditors at the time.

31. Comparative Financial Statements

The comparative consolidated financial statements have been reclassified from the ones previously presented to conform to the

presentation of the current consolidated financial statements.

2016 2015

Cash income taxes paid 8,510$ 84,709$

Cash interest paid 30,729 262,154

Cash interest received 11,212 6,427


Documents

Management’s Responsibility for Financial Statements · Management’s Responsibility for Financial Statements ... Restructuring and severance costs 1 154,855 18,311 ... LIABILITIES