Pacific Announces Fourth Quarter & Year End 2016 Results and Updates Its 2016 Year-End Reserves
Mar 15, 2017

TORONTO, March 15, 2017 /CNW/ - Pacific Exploration & Production Corporation (TSX: PEN) ("Pacific" or the "Company") announced today the release of its consolidated financial statements for the year and quarter ended December 31, 2016, together with its management discussion and analysis ("MD&A"), Annual Information Form ("AIF") and Form 51-101 F1 - Statement of Reserves Data and Other Oil and Gas Information for the Company (the "F1 Report") in respect of the year ended December 31, 2016. These documents, among others, will be posted on the Company's website at www.pacific.energy and SEDAR at www.sedar.com. All values in this news release and the Company's financial disclosures are in United States dollars unless otherwise stated.

Gabriel de Alba, Chairman of the Board of Directors, commented:

"The past year was one of significant change for Pacific, financially, operationally and culturally. The Company emerged from its restructuring with a new Board of Directors and management team and a plan focused on capital discipline and value maximization. We were able to deliver stable results through the end of 2016 and are now starting to see positive momentum in our core E&P efforts during the first two months of 2017. Combined with an ongoing review of assets and a targeted cost reduction program, we believe that we can continue to expand on this positive performance."

Barry Larson, Chief Executive Officer of the Company, commented:

"While 2016 results were primarily impacted by the expiration of the Rubiales and Piriri fields mid-year and lower drilling activity as a result of reduced capital expenditures during the Company's significant and successful restructuring process, I am very pleased with the amount of progress made on our plan to reduce costs, rationalize our portfolio and allow for a dedicated focus on high return opportunities on our core E&P assets in Colombia and Peru. We have a significant opportunity to create future growth and with capital discipline and operational rigor, we will take every step to create long-term value for our shareholders."

Full Year and Fourth Quarter 2016 Results

Operational Results:

  • For 2016, the Company's average daily net production after royalties was 103,532 boe/d, 33% lower compared with the previous year.
  • Fourth quarter 2016 average daily net production after royalties decreased to 69,432 boe/d, lower by 57% as compared to the same period of 2015.
  • The decrease in production was mainly attributable to the expiration of the Rubiales-Piriri contract on June 30, 2016, and lower production in other fields due to lower drilling activity and fourth quarter operational issues related to water disposal capacity.
  • During 2016, the combined oil and gas operating cost was $22.78/boe, slightly higher compared with $22.48/boe for 2015 due to higher production and transportation costs but ameliorated by lower dilution costs. Average production cost was higher due to lower volume produced, and transportation cost rose as a result of slightly higher tariffs on the main pipelines.  Dilution cost was lower because of the Company's strategy to utilize alternative dilution arrangements.
  • In 2016 the Company entered into several operational collaborative agreements with third parties in Colombia which resulted in savings in dilution cost and fuel cost.

 

Financial Results:

  • Revenue decreased to $1,412 million from $2,825 million in 2015, and for the fourth quarter of 2016 to $270 million from $652 million for the same period in 2015.
  • Operating EBITDA was $445 million for 2016 and $44 million for the fourth quarter of 2016, lower compared to $1,166 million in 2015 and $235 million in the fourth quarter of 2015.
  • The decreases in revenue and operating EBITDA were due to the nearly 16% year-on-year decline in realized crude oil prices, the expiration of the Rubiales-Piriri contract and $138 million lower realized gains from oil hedging contracts compared with 2015.
  • Total volume of oil and gas sales (including trading) for the year 2016 averaged 95,496 boe/d, 40% lower than the 159,113 boe/d in 2015 mainly due to the expiration of the Rubiales-Piriri fields in June 2016 and the lower production in other fields due to lower drilling activity as a result of reduced capital expenditures during the Company's restructuring process.
  • Oil and gas operating netback for 2016 was $17.58/boe, 32% or $8.45 lower than the previous year. In 2016, combined realized price declined by $8.15 compared to the previous year indicating that 96% of the decline in combined operating netback in 2016 was attributable to the decline in global crude prices.
  • The Company's average sales price per barrel of crude oil and natural gas was $40.36/boe in 2016, down from $48.51/boe in 2015. Operating netback in the fourth quarter of 2016 decreased to $13.94/boe from $19.21/boe in the same period of 2015 due to lower volumes sold.
  • General and Administrative ("G&A") costs (excluding restructuring and severance expenses) decreased to $145 million in 2016 and $40 million in the fourth quarter of 2016 from $203 million in 2015 and $55 million in the fourth quarter of 2015; the Company continues to reduce G&A and all non-essential spending activities.
  • Net Income for 2016 was $2,449 million, largely due to non-cash items and one-time items, including the recognition of a net gain of $3.6 billion on the cancellation of the debt held by the Affected Creditors in exchange for the issuance of new common shares and $155 million in costs related to the Restructuring Transaction.
  • The Company recorded net impairment charges of $477 million for 2016, which included impairment losses of $1,114 million during the first three quarters and a reversal of impairment of $637 million in the fourth quarter of the year.  Impairment tests were performed at the end of 2016 based on the reserves certified by external evaluators as of December 31, 2016.
  • Total capital expenditures decreased to $161 million in 2016 compared with $726 million in 2015 as the Company focused on preserving cash through the restructuring process.

 

Additional Highlights:

  • The Company continues to negotiate field commitments to focus on high-impact development drilling. On March 17, 2016, the Agencia Nacional de Hidrocarburos ("ANH") approved the transfer of $38 million in exploration commitments from Las Aguilas, Castor, LL-59, LL-15 and CPE-1 blocks to the Casanare Este, Mapache, Guatiquia, Guama LL-83 and Rio Ariari blocks. On November 22, 2016, the ANH approved a second investment transfer totaling $19 million from the CPO 14, Sabanero, LL-19 and Topoyaco blocks to the LL-25 Block.
  • The Company successfully completed the divestment of all non-core assets in Brazil. On September 27, 2016, the Company reached an agreement with partners Karoon Gas Australia Ltd. and Karoon Petroleo e Gas Ltda. (collectively, "Karoon"), to sell the Company's 35% working interest in the joint concession agreements in Brazil for $15.5 million in cash consideration. The transaction was approved by the Brazilian regulator on January 31, 2017.
  • On October 14, 2016, the Company also reached an agreement with partner Queiroz Galvão Exploração e Produção S.A. ("Queiroz") to withdraw from joint working interests; the Company will pay $10 million in exchange for release from future work commitments in the aggregate amount of $76.3 million. The Queiroz transaction was approved by the Brazilian regulator on March 13, 2017, and is expected to be fully consummated shortly subject to the amendment of the concession agreements. Also as a result of the transaction, the Company will be released from approximately $41 million of letter of credit requirements.
  • On November 30, 2016 the Company and Compañía Española de Petróleos ("CEPSA") Peru entered into an agreement, whereby CEPSA agreed to acquire our 30% participating interest in the Licence Agreement for Block 131, in which CEPSA Peru is the operator. The sale price is $17.8 million with adjustment based on future cash flow from the block; the transaction is subject to Peruvian regulatory approval.

 

Financial Results:

         

Financial Summary

       
 

Year Ended
December 31

Three Months
Ended December 31

 

2016

2015

2016

2015

Oil & Gas Sales Revenues ($ millions)

1,411.7

2,824.5

269.8

652.0

Operating EBITDA ($ thousands)1

444,637

1,165,758

44,275

224,911

Operating EBITDA Margin (Operating EBITDA/Revenues)

31%

37%

16%

34%

Consolidated EBITDA ($ thousands)1

253,619

1,111,566

(1,967)

257,584

Consolidated EBITDA Margin (Consolidated EBITDA/Revenues)

18%

39%

(1)%

40%

Net income (Loss)3

2,448,523

(5,461,859)

4,025,194

(3,895,908)

Per share – basic ($)2

48.97

(1,733,923)

80.50

(1,236,713)

Net Production (boe/d)

103,532

154,472

69,432

159,831

Sales Volumes (boe/d)

95,496

159,113

69,653

171,928

(COP$ / US$) Exchange Rate4

3,000.71

3,149.47

3,000.71

3,149.47

Average Shares Outstanding – basic (thousands)

50,002.4

3.2

50,002.4

3.2

1

These metrics are Non-GAAP financial measures. See below Advisories "Non-GAAP Financial Measure" and "Non-GAAP Measures on page 20" in the MD&A.

2

The basic weighted average numbers of common shares for the years ended December 31, 2016 and 2015 were 50,002,363 and 3,150, respectively.

3

Net Income (loss) attributable to equity holders of the parent.

4

COP/USD exchange rate fluctuations can have a significant impact on the Company's accounting net earnings, in the form of unrealized foreign currency translation on the Company's financial assets and liabilities and deferred tax balances that are denominated in COP.

 

Production:

         

Net Production Summary

       
 

Year Ended
December 31

Three Months Ended
December 31

 

2016

2015

2016

2015

Oil (bbl/d)

       

Colombia

91,663

139,659

60,150

138,906

Peru

3,106

5,586

2,079

10,462

Total Oil (bbl/d)

94,769

145,245

62,229

149,368

         

Natural Gas (boe/d)

       

Colombia

8,763

9,227

7,203

10,463

Total Natural Gas (boe/d)

8,763

9,227

7,203

10,463

Total Equivalent Production (boe/d)

103,532

154,472

69,432

159,831

 

During 2016, net production after royalties and internal consumption totaled 103,532 boe/d, representing a decrease of 51,120 boe/d (33%) from the average net production of 154,472 boe/d reported in the previous year. This reduction is mainly attributable to the expiration of the Rubiales and Piriri fields, both of which were returned to Ecopetrol on June 30, 2016. Additionally, heavy oil production from Quifa SW and other fields decreased by 16% in comparison to 2015, mainly due to lower drilling activity and operational issues with water disposal capacity mainly due to temporary pump failures.

Light and medium net oil production in Colombia and Peru totaled 42,713 bbl/d, decreasing by 25% compared with 2015. The overall decrease was primarily due to lower drilling activity as a result of reduced capital expenditures during the Company's restructuring process in 2016. Light and medium oil and heavy oil production (excluding production at the Rubiales field) now represent 41% and 27%, respectively, of total net oil and gas production. Additionally, gas production decreased by 5% compared with the year 2015 due to reservoir water encroachment issues, and as of December 31, 2016 represented 8% of the total production.

2016 Reserves:

For the year ended December 31, 2016, the Company received independent certified reserves evaluation reports for all of its assets with total net 2P reserves of 170.7 MMboe. Compared with 290.8 MMboe certified for the year ended 2015, the year-over-year decline is mainly due to production for the year, the lower oil price forecasts resulting in economic revisions and the impact of technical revisions as assessed by the Company's independent reserves evaluators. Proved net reserves of 117.3 MMboe now represent 69% of the total 2P reserves compared with 68% of the total 2P reserves in 2015.

The following tables summarize information contained in the independent-reserves reports prepared by RPS Energy Canada Ltd. ("RPS") and Degolyer and MacNaughton ("D&M") effective December 31, 2016.

These reserves reports were prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and the National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and included in the F1 Report filed on SEDAR. Additional reserves information as required under NI 51-101 can also be found on SEDAR, under the: (i) Forms 51-101F2 – Report on Reserves Data by Independent Qualified Reserves Evaluator completed by each of RPS and D&M dated February 27, 2017; and (ii) Form 51-101F3 – Report of Management and Directors on Oil and Gas Disclosure dated March 15, 2017.

All reserves presented are based on forecast pricing and estimated costs effective December 31, 2016 as determined by the Company's independent reserves evaluators. The Company's net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates, including any additional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end 2016.

 

Reserves at December 31, 2016 (MMboe1)

Country

Field

Total Proved
(P1)

Probable (P2)

Proved Plus Probable
(2P)

Hydrocarbon Type

Gross

Net

Gross

Net

Gross

Net

Colombia

Quifa SW

47.2

41.3

3.5

3.0

50.7

44.3

Heavy Oil

               

Other Heavy Oil Blocks2

32.5

28.1

14.5

12.2

47.0

40.3

Heavy Oil

               

Light/Medium Oil Blocks

38.8

35.7

28.0

25.7

66.8

61.4

Light & Medium Oil &
Associated Natural Gas

               

Natural Gas Blocks3

6.7

6.7

7.9

7.9

14.6

14.6

Natural Gas

Sub-total

125.3

111.8

53.8

48.7

179.1

160.5

Oil & Natural Gas

Peru

Light/Medium Oil & Natural Gas4

6.5

5.5

4.7

4.7

11.2

10.2

Oil & Natural Gas

 

Total at Dec. 31, 2016

131.8

117.3

58.5

53.4

190.3

170.7

Oil & Natural Gas

Total at Dec. 31, 2015

216.6

197.8

101.2

93.0

317.8

290.8

 

Difference

(84.8)

(80.5)

(42.7)

(39.6)

(127.5)

(120.1)

 

2016 Production

41.9

37.9

Total Reserves
Incorporated

(85.6)

(82.2)

 

Notes:

1

See "Boe Conversion" section in the Advisories, at the end of this news release.

2

Includes Cajua, Jaspe, Quifa North, Sabanero, CPE-6 and Rio Ariari properties.

3

Includes La Creciente Field.

4

Includes onshore Block 131, Block 192 and offshore Block Z1.

In the table above, Gross refers to WI before royalties, Net refers to WI after royalties; numbers in table may not add due to rounding differences.

 

 

 

2016 2P Reserves Reconciliation

 

Oil Equivalent
Gross 2P Reserves
(MMboe)

Oil Equivalent Net
2P Reserves
(MMboe)

December 31, 2015

317.8

290.8

Net Additions and Technical Revisions

(38.3)

(40.5)

Economic Revisions

(47.2)

(41.6)

Production1

(41.9)

(37.9)

December 31, 2016

190.3

170.7

Notes:

1

Production represents the production for the twelve month period ended December 31, 2016.

Note: Numbers in the table may not add due to rounding differences.

 

Fourth Quarter and Year End 2016 Conference Call Details:

As previously disclosed, a conference call for investors and analysts is scheduled for Thursday, March 16, 2017 at 8:30 a.m. (Bogotá time) and 9:30 a.m. (Toronto time). Participants will include Gabriel de Alba, Chairman of the Board of Directors, Barry Larson, Chief Executive Officer, Camilo McAllister, Chief Financial Officer and select members of the senior management team.

A presentation will be available on the Company's website prior to the call, which can be accessed at www.pacific.energy.

Analysts and interested investors are invited to participate using the following dial-in numbers:

Participant Number (International/Local):

(647) 427-7450

Participant Number (Toll free Colombia):

01-800-518-0661

Participant Number (Toll free North America): 

(888) 231-8191

Conference ID:

85651976

 

Webcast:  http://www.pacific.energy/en/webcast

A replay of the conference call will be available until 10:59 p.m. (Bogotá time) and 11:59 p.m. (Toronto time), Thursday, March 30, 2017 and can be accessed using the following dial-in numbers:

Encore Toll Free Dial-in Number:

1-855-859-2056

Local Dial-in-Number:

(416)-849-0833

Encore ID:

85651976

 

About Pacific:

Pacific is a Canadian public company and a leading explorer and producer of natural gas and crude oil, with operations focused in Latin America. The Company has a diversified portfolio of assets with interests in more than 45 exploration and production blocks in various countries including Colombia, Peru and Belize. The Company's strategy is focused on sustainable growth in production & reserves and cash generation. Pacific is committed to conducting business safely, in a socially and environmentally responsible manner.

The Company's common shares trade on the Toronto Stock Exchange under the ticker symbol PEN.

Advisories:

Cautionary Note Concerning Forward-Looking Statements

This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates and/or assumptions in respect of production, revenue, cash flow and costs, reserve and resource estimates, potential resources and reserves and the Company's exploration and development plans and objectives) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; uncertainties associated with estimating oil and natural gas reserves; failure to establish estimated resources or reserves; volatility in market prices for oil and natural gas; fluctuation in currency exchange rates; inflation; changes in equity markets; perceptions of the Company's prospects and the prospects of the oil and gas industry in Colombia and the other countries where the Company operates or has investments as the result of the completion of the Company's comprehensive restructuring transaction or otherwise; uncertainties relating to the availability and costs of financing needed in the future; the uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 14, 2017 filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this press release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.

Non-GAAP Financial Measures

This report contains the following financial terms that are not considered in IFRS: Operating and Consolidated EBITDA, and Operating, Consolidated and Cash Netback. These non-IFRS measures do not have any standardized meaning, and therefore are unlikely to be comparable to similar measures presented by other companies. These non-IFRS measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity. They are different from those measures disclosed in prior periods, reflecting the Company's new strategic focus on operational efficiency and capital discipline.

Management believes that Netback is a useful measure to assess the net profit after all the costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performances expressed as profit per barrel.

  • Operating Netback represents realized price per barrel plus realized gain or loss on financial derivatives, less production costs, transportation cost and diluent cost, and shows how efficient the Company is at extracting and selling its product.
  • Consolidated Netback represents Operating Netback plus the results from corporate investments such as the Company's pipeline investments that are in addition to oil and gas production and the take-or-pay tariffs paid on disrupted pipelines.
  • Cash Netback represents Consolidated Netback less corporate cash expenses (general and administrative expenses and cash finance costs).

 

Management believes that EBITDA is a common measure used to assess profitability before the impact of different financing methods, income taxes, depreciation and impairment of capital assets and amortization of intangible assets.

  • Operating EBITDA represents the operating results of the Company's primary business, excluding the effects of capital structure, other investments (infrastructure assets), non-cash items that depend on accounting policy choices, and one-time items that are not expected to recur.
  • Consolidated EBITDA excludes items of a nonrecurring nature (one-time items), or that could make the period-over-period comparison of results from operations less meaningful, but includes results from the Company's other investments (infrastructure assets).

 

A reconciliation of Operating and Consolidated EBIDA to net earnings is as follows:

 

Year Ended
December 31

Three Months Ended
December 31

(in thousands of US$ )

2016

2015

2016

2015

         

Net income (loss)(1)

$        2,448,523

$        (5,461,859)

$        4,025,194

$        (3,895,908)

         

Adjustments

       

Income tax expense (recovery)

36,175

(466,514)

(2,778)

(358,669)

Depletion, depreciation and amortization

575,985

1,529,016

85,700

380,281

Impairment and exploration expenses

477,005

4,907,209

(636,594)

3,890,229

Finance costs

191,245

434,846

66,497

205,917

Net gain on restructuring

(3,620,481)

-

(3,620,481)

-

Restructuring and severance costs

154,855

18,311

55,034

7,870

Equity tax

26,901

39,149

-

-

Other (income) expenses

(25,967)

80,992

15,661

27,914

Foreign exchange unrealized (gain) loss

(10,622)

30,416

9,800

(50)

Consolidated EBITDA

253,619

1,111,566

(1,967)

257,584

Loss (gain) on risk management

139,457

(129,474)

13,471

(61,553)

Share of (gain) loss of equity-accounted investees

(62,840)

(21,537)

4,253

(7,875)

Gain (loss) attributable to non-controlling interest

15,288

(21,112)

5,085

(20,265)

Share based compensation (gain) loss

(7,775)

(1,564)

728

(6,245)

Foreign exchange realized loss

1,759

104,061

4,057

21,446

Fees paid on suspended pipeline capacity

105,129

123,818

18,648

41,819

Operating EBITDA

$           444,637

$         1,165,758

$             44,275

$            224,911

   

1.

Net gain (loss) attributable to equity holders of the parent

 

 

2016

2015

(in thousands of US$ )

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

                 

Financial and Operational results:

               
                 

Operating EBITDA

44,275

89,846

120,452

190,064

224,911

331,974

335,235

273,638

                 

Consolidated EBITDA

(1,967)

37,689

126,083

91,814

257,584

414,550

196,592

242,840

                 

 

Please see the Company's most recent Management's Discussion and Analysis, which is available at www.sedar.com for additional information about these financial measures.

Boe Conversion

The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 5.7 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The Company's natural gas reserves are contained in the La Creciente, Guama and other blocks in Colombia as well as in Block Z-1, Peru. For all natural gas reserves in Colombia, boe's have been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy, and for all natural gas reserves in Peru, boe's have been expressed using the Peruvian conversion standard of 5.626 Mcf: 1 bbl required by Perupetro S.A. If a conversion standard of 6.0 Mcf: 1 bbl was used for all of the Company's natural gas reserves, this would result in a reduction in the Company's net 1P and 2P reserves of approximately 4.9 and 6.9 MMboe, respectively.

Definitions

Bcf

Billion cubic feet.

Bcfe

Billion cubic feet of natural gas equivalent.

bbl

Barrel of oil.

bbl/d

Barrel of oil per day.

boe

Barrel of oil equivalent. Boe's may be misleading, particularly if used in isolation. The
Colombian standard is a boe conversion ratio of 5.7 Mcf:1 bbl and is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

boe/d

Barrel of oil equivalent per day.

Mbbl

Thousand barrels.

Mboe

Thousand barrels of oil equivalent.

MMbbl

Million barrels.

MMboe

Million barrels of oil equivalent.

Mcf

Thousand cubic feet.

Million Tons
LNG

One million tons of LNG (Liquefied Natural Gas) is equivalent to 48 Bcf or
1.36 billion m3 of natural gas.

Net Production

Company working interest production after deduction of royalties.

Total Field
Production

100% of total field production before accounting for working interest and
royalty deductions.

Gross
Production

Company working interest production before deduction of royalties.

WTI

West Texas Intermediate Crude Oil.

 

SOURCE Pacific Exploration and Production Corporation

For further information: Richard Oyelowo, Manager, Investor Relations, +1 (416) 362-7735, ir@pacificcorp.energy