Pacific Releases Certain Projected Financial Information

TORONTO, April 20, 2016 /CNW/ - Pacific Exploration & Production Corporation ("Pacific" or the "Company") entered into confidentiality agreements (the "Confidentiality Agreements") with certain members of the Ad Hoc Committee of holders of the Company's senior unsecured notes ("Notes") to facilitate discussions about a possible restructuring transaction. Pursuant to the Confidentiality Agreements, the Company disclosed information, including certain non-public information (the "Non-Public Information"), through the Ad Hoc Committee's legal and financial advisors to those holders of Notes (the "Restricted Noteholders") who entered into the Confidentiality Agreements. This information was provided to Restricted Noteholders in order to consider their support of, and possible participation in, a potential restructuring and by agreeing to be restricted, such Restricted Noteholders were prohibited from trading in the securities of the Company or using the Non-Public Information for any other purpose than considering a potential restructuring.

This news release contains the Non-Public Information that is required to be disclosed to satisfy the Company's obligations under the Confidentiality Agreements to now disclose such Non-Public Information.

As described in the Company press releases on April 19, 2016 and April 20, 2016, the Company has entered into an agreement with The Catalyst Capital Group Inc., certain members of the Ad Hoc Committee and certain of the Company's lenders under its credit facilities to effect a comprehensive financial restructuring (the "Restructuring Transaction") that will significantly reduce debt, improve liquidity, and best position the Company to navigate the current oil price environment.

The Company does not, as a matter of course, publish its business plans, budgets or strategies or make external projections or forecasts of its anticipated financial position, capital expenditures, capital requirements, cash flow, production plans and costs, or results of operations or the assumptions forming the basis for such projections or forecasts. The Non-Public Information provided to certain holders of Notes is included in this news release only because such information was made available to these holders of Notes; therefore, the inclusion of any Non-Public Information in this news release should not be regarded as an indication that the Company or any other person considered, or now considers, this information to be necessarily predictive of actual future results, and does not constitute an admission or representation by any person that such information is material, or that the expectations, beliefs, opinions, and assumptions that underlie such information remain the same as of the date of this news release. The Company has not made any determination as to whether the Non-Public Information disclosed pursuant to the Confidentiality Agreements may be, or may be deemed to be, in whole or in part, material to a person in making an investment decision or for any other purpose.

The Non-Public Information was, when provided to certain holders of Notes, and continues to be, speculative by its nature and was, and is, based upon numerous expectations, beliefs, opinions, and assumptions, as further described below, and it does not necessarily reflect current estimates, expectations, beliefs, opinions, or assumptions and may not reflect current results or expected future performance. The Non-Public Information provided to certain holders of Notes, and therefore contained herein, may be incomplete or may no longer be accurate and is subject to interpretation. Accordingly investors are cautioned not to place undue reliance on such information or forward-looking statements.

The Non-Public Information has not been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and therefore does not have any standardized meaning prescribed by the IASB and is therefore unlikely to be comparable to similar measures presented by other issuers. Neither the independent auditor of the Company nor any other independent accountant has examined, compiled, or performed any procedures with respect to the Non-Public Information contained herein and, accordingly, none has expressed any opinion or any other form of assurance on such information or its achievability and none assumes any responsibility for the prospective financial information.

Subject to applicable securities law, the Company does not intend to or anticipate that it will, and disclaims any obligation to, furnish updated business plans, budgets, strategies, projections or forecasts or similar forward-looking information to holders of securities issued by the Company or to include such information in documents required to be filed with the applicable Canadian regulators. These considerations should be taken into account in reviewing the forward-looking information included herein, which was prepared as of an earlier date.

While presented in this news release with numeric specificity, the projections and other forward-looking financial information were not, when made, and are not historical facts, but represent forward-looking statements about the objectives, plans, strategies, goals, financial conditions, results of operations, activities and businesses of the Company at the time prepared and are subject to important risks, uncertainties and assumptions. The forward-looking statements set out in this news release are based upon the Company's reasonable estimates, assumptions and expectations about its business, operations, financial condition, and the markets in which it operates, and upon other third party information and data such as analyst reports, market studies and government projections, in each case available at the time such information was prepared and are subject to significant business, operational, economic, competitive and other uncertainties and contingencies (including those set out under the heading "Risk Factors" and elsewhere in the Company's Annual Information Form dated March 18, 2016 and filed on SEDAR and available at www.sedar.com).

Forward-looking statements are subjective in many respects and reflect numerous assumptions by the Company with respect to future events, economic, competitive and regulatory conditions, financial market conditions and future business decisions, including, but not limited to, the following key assumptions: (i) no material adverse impact on the Company's business on a going forward basis resulting from the Restructuring Transaction or otherwise; (ii) a continuation of business arrangements on substantially the same basis as existed prior to the Restructuring Transaction (other than as those business arrangements that may be impacted by the implementation of the Restructuring Transaction); (iii) the future price of oil and natural gas, fluctuations in inflation and exchange rates, and other economic matters; and (iv) the Company's ongoing operations, including its costs to extract oil and natural gas, production rates, availability of labour and equipment, the possibility of labour strikes or work stoppages, or governmental intervention or regulation relating to production, exploration and development, environmental protection, health and safety and other matters.

The results, estimates, projections, events or other forward-looking information predicted in any forward-looking statements may differ materially from actual results or events if known or unknown risks, trends or uncertainties affect the Company's business, or if the Company's estimates or assumptions turn out to be inaccurate. Some assumptions may not materialize, and results, estimates, projections, events and circumstances occurring subsequent to the date on which the information was prepared may be different from those assumed or may be unanticipated, and thus may affect the forward-looking statements in a material manner. In addition, the information in this news release does not contemplate outcomes where the Company is unable to complete the Restructuring Transaction. Accordingly, it is expected that there will be differences between actual and projected amounts and results, and actual amounts and results may be materially different from those in this news release and there can be no assurance that any projection, estimate or forecast will materialize.

All dollar amounts set out below are in U.S. dollars, unless otherwise stated.

The Company regularly generates internal cash flow forecasts, which it updates from time to time as circumstances change.  On or about February 29, 2016, one such internal forecast was provided to the advisors to the Ad Hoc Committee for distribution to Restricted Noteholders (the "13 Week Cash Flow Forecast").  The 13 Week Cash Flow Forecast covers the period from February 6, 2016 to May 28, 2016. The 13 Week Cash Flow Forecast showed that, assuming a crude oil price based on Brent of $33.40 in February 2016, $36.55 in March 2016, $37.18 in April 2016 and $37.77 in May 2016, and assuming production of oil during that same period was 146,873 bbl/d in February 2016, 143,454 bbl/d in March 2016, 139,159 bbl/d in April 2016 and 135,427 bbl/d in May 2016, the Company expected, based upon these and other assumptions, that it would have a gross closing cash balance of approximately $75.5 million at the end of the period covered by the 13 Week Cash Flow Forecast and that during this same period total disbursements (including capital expenditures) would be greater than total receipts by $247.1 million. Note that in the 13 Week Cash Flow Forecast, the projected Brent crude oil prices for Februrary and March were higher than the projected realized Brent crude oil prices utilized therein to project receipts.

A summary of the 13 Week Cash Flow Forecast is set out below:

LIQUIDITY FORECAST DATED FEBRUARY 29, 2016


March

April

May

Memo: Brent Price

$36.55

$37.18

$37.77





Receipts





Oil and Gas Exports

$104.4

$117.4

$107.6


Hedge

0.0

0.0

0.0


Others

25.5

0.0

0.0

Total Receipts

$129.9

$117.4

$107.6





Disbursements





Debt: Bonds, Fees

($1.9)

($0.4)

$0.0


Pipelines

(60.2)

(61.2)

(61.1)


Cash Calls Colombia

(49.2)

(32.7)

(13.5)


Cash Call Perú

(14.3)

(5.7)

(19.5)


Other

(97.9)

(90.8)

(93.7)

Total Disbursements

($223.5)

($190.8)

($187.8)





Total Receipts less Total Disbursements

(93.6)

(73.4)

(80.2)

Cash and Cash Equivalents




Cash and Cash Equivalents in Cash Operating Accounts





Beginning

$249.2

$155.6

$82.2


(+) Total Receipts less Total Disbursements

(93.6)

(73.4)

(80.2)


Ending

$155.6

$82.2

$2.0





JVA Cash and Cash Equivalents (Local + Perú + Midstream )

$23.0

$23.0

$23.0

Others Cash and Cash Equivalents

20.8

20.8

20.8

Restricted Cash and Cash Equivalents

29.6

29.6

29.6

GROSS CLOSING CASH AND CASH EQUIVALENTS

$229.0

$155.7

$75.5





Memo:





Disbursements - Other






Third-Party Oil/Fuels

($0.4)

($0.3)

($0.3)



Thinner

(8.0)

(9.9)

(9.7)



Royalties & ANH

(4.6)

(1.6)

(1.6)



Ground Transportation

(7.9)

(9.0)

(11.1)



Endorsements (TR14 & Estimated)

(0.9)

(0.0)

(0.0)



Suppliers (Mandatory TR14)

(6.0)

(2.9)

(3.3)



Payroll

(13.5)

(12.2)

(11.7)



Taxes

(8.4)

(8.1)

(19.2)



Payments to Suppliers under Special Agreement

(8.9)

(7.6)

(7.2)



Other: Corporate Payments and Supplier Payments upon Contract End

(0.7)

0.0

0.0



Suppliers (Non-Mandatory)

(12.6)

(26.4)

(23.7)



Other Cash Calls (excluding Colombia and Perú)

(16.4)

(7.6)

(3.8)



Fees (Legal and Financial Advisors)

(9.6)

(5.1)

(2.2)



Total Disbursements - Other 

(97.9)

(90.8)

(93.7)

 

As of April 8, 2016, the Company had issued letters of credit for a total of $197 million. Pacific's management team has ongoing negotiations with its exploration partners and various banks to manage its exploration commitments and collateralization of letters of credit. The Company's projected cash collateralization of letters of credit through the end of 2016 is listed below.

(USD)

Apr-16

May-16

Jun-16

Jul-16

Aug-16

Sep-16

Oct-16

Nov -16

Dec-16

Total












RCF Banks

Bladex1

-

-

-

-

-

-

-

-

-

-

BofA2

8,003,314

-

2,697,112

-

-

-

-

-

-

10,700,425

Citibank

-

1,649,520

-

-

-

-

-

600,000

-

2,249,520

Corpbanca

300,000

116,000

8,900,000

-

-

-

-

779,389

2,018,743

12,114,132

Davivienda

-

-

12,962,707

-

-

300,000

200,000

-

360,000

13,822,707

Santander

-

-

-

-

-

-

-

-

-

-












Non RCF Banks

Bancolombia3

-

9,413,125

-

-

-

-

-

-

-

9,413,125

BBVA

-

-

1,200,762

-

-

611,398

-

-

-

1,812,160

BCP

300,000

-

-

1,560,000

-

-

-

-

-

1,860,000

Occidente

112,080

184,444

-

-

1,909,251

-

-

-

-

2,205,775

BBVA Continental

-

-

-

-

-

-

-

-

-

-

GNB Sudameris

-

-

-

-

-

-

-

-

-

-


Total

8,715,394

11,363,089

25,760,581

1,560,000

1,909,251

911,398

200,000

1,379,389

2,378,743

54,177,844




Notes:




(1)

Bladex LC will be renewed for 6 months




(2)

BofA exposure was reduced given the reduction on the OB Transportation Tariff




(3)

Bancolombia SBLC currently guarantees the Block CPO-14, the Company is currently negotiating to reduce this SBLC

 

The Company also regularly generates internal business plans, which it updates from time to time as circumstances change.  On or about February 29, 2016, one such internal business plan was provided to the advisors to the Ad Hoc Committee for distribution to the Restricted Noteholders (the "February Business Plan"). Attached hereto as Appendix A is substantially the form of the February Business Plan. In March 2016, the Company provided to the Ad Hoc Committee for distribution to the Restricted Noteholders an Additional Scenarios Addendum to the February Business Plan (the "March Business Plan" and, collectively with the February Business Plan, the "Business Plan"). Attached hereto as Appendix B is substantially the form of the March Business Plan. The Business Plan covered the calendar years 2016 to 2020.

The Business Plan reflected possible outcomes under two distinct pricing assumptions, as follows (note that the pricing in the Company's Base Case for the years 2016 and 2017 reflects a discount to the Brent Benchmark that causes the Base Case realized price to be lower than the Strip Case realized price for these years):

Pricing ($/boe)

2016E

2017E

2018E

2019E

2020E

Brent Benchmark

37.39

43.22

64.97

67.11

67.69

Base Case

(realized price)

26.29

31.39

53.51

54.77

54.00

Strip Case

(realized price)

30.93

36.93

53.51

54.77

54.00

The Business Plan used the following assumptions with respect to production:

Production
(boe/d)

2016E

2017E

2018E

2019E

2020E

Oil

98,322

70,811

69,481

61,473

47,263

Gas

11,067

11,909

15,911

16,427

16,139

Net Production (boe/d)

109,389

82,720

85,392

77,900

63,401

The Business Plan also relied upon the following additional key assumptions:

  • All hedges are unwound and settled by February 2016;

  • Total hedge cash proceeds are $195 million in 2016, including collection of $67 million for December 2015 hedges;

  • Operating expenses increase from $27.98/boe to $30.79/boe from 2016 to 2020;

  • SG&A of $167 million in 2016 and $140 million per year thereafter;

  • The Company had $207 million of withholding tax receivable at December 31, 2015. $61 million would be collected in 2016 and $135 million would be collected in 2017. The remaining $11 million would not be collected during the forecast period;

  • Outstanding VAT receivables at December 31, 2015 of $109 million;

  • Equity tax payments of $27 million in 2016;

  • A required minimum cash balance of $100 million;

  • An unrestricted cash balance of $250 million existed as of December 31, 2015;

  • Professional fees were assumed to be $10 million per month in 2016, payable one month after incurrence; and

  • OBC Pipeline is available 48% of the time ("OBC 48").

Based upon the foregoing assumptions, among others, a summary of the Business Plan, based upon the Base Case pricing assumption is set out below (note that the pricing in the Company's Base Case for the years 2016 and 2017 reflects a discount to the Brent Benchmark that causes the Base Case realized price to be lower than the Strip Case realized price for these years):


2016 – 2020 Annual

Period Ending

12/31/16

12/31/17

12/31/18

12/31/19

12/31/20

(all figures in USD thousands, unless otherwise stated)












Production (boe/d)

109,389

82,720

85,392

77,900

63,401

Average Realized Price ($/boe)

26.29

31.39

53.51

54.77

54.00

Discount to Brent Benchmark ($/boe)

4.99

5.30

11.44

12.33

13.69







Starting Cash Balance

$250,000

$100,000

$100,000

$100,000

$100,000







Total Revenues

1,087,450

988,668

1,732,279

1,624,166

1,320,570







Production & Operating Costs

1,154,278

860,562

937,301

884,755

779,777

SG&A Cost

167,000

140,000

140,000

140,000

140,000


Total Costs

1,321,278

1,000,562

1,077,301

1,024,755

919,777








EBITDA

(233,828)

(11,894)

654,978

599,411

400,793







Capital Expenditures

118,577

435,154

558,313

306,371

250,926







EBITDA - Capex

(352,404)

(447,048)

96,666

293,040

149,866







Hedging Cash Impacts

194,701

-

-

-

-

Asset Sales

162,200

-

-

-

-

Midstream Cash Dividends

37,079

-

-

-

-

Equity Tax Payments

(26,546)

-

-

-

-

Capital Lease Payments

(17,474)

(6,787)

(6,778)

(6,778)

(6,797)

Other One-Time Items

(32,316)

(6,000)

-

-

-


Other Inflows / (Outflows)

317,643

(12,787)

(6,778)

(6,778)

(6,797)

Changes in Accounts Receivable

126,377

(4,968)

(45,651)

4,793

18,498

Changes in Tax Receivables

41,500

144,164

(20,371)

(8,792)

(9,522)

Changes in Inventory

(15,469)

2,578

(3,148)

904

2,546

Changes in Accounts Payable

(448,741)

91,802

57,800

(79,783)

(30,281)

One-Time Working Capital Impacts

(93,152)

-

-

-

-


Net Change in Working Capital

(389,486)

233,576

(11,370)

(82,878)

(18,759)







Cash Flow Before Restructuring Costs

(424,246)

(226,260)

78,517

203,383

124,310

Professional  Fees

110,000

10,000

-

-

-


Restructuring  Costs

110,000

10,000

-

-

-







Aggregate  Cash Flow

(534,246)

(236,260)

78,517

203,383

124,310







DIP Draw / (Repayment)

384,246

236,260

(78,517)

(203,383)

(124,310)







Ending Cash Balance

100,000

100,000

100,000

100,000

100,000







Cumulative DIP Draw

384,246

620,506

541,989

338,605

214,295

Under the Base Case OBC 48 scenario, the maximum DIP draw in 2016 is $429.6 million, occurring in November 2016.

Based upon the foregoing assumptions, among others, a summary of the Business Plan, based upon the Strip + Consensus Case pricing assumption is set out below:


2016 – 2020 Annual

Period Ending

12/31/16

12/31/17

12/31/18

12/31/19

12/31/20

(all figures in USD thousands, unless otherwise stated)












Production (boe/d)

109,389

82,720

85,392

77,900

63,401

Average Realized Price ($/boe)

30.93

36.93

53.51

54.77

54.00

Discount to Brent Benchmark ($/boe)

5.87

6.24

11.44

12.33

13.69







Starting Cash Balance

$250,000

$100,000

$100,000

$100,000

$114,359







Total Revenues

1,273,183

1,155,900

1,732,279

1,624,166

1,320,570







Production & Operating Costs

1,154,278

860,562

937,301

884,755

779,777

SG&A Cost

167,000

140,000

140,000

140,000

140,000


Total Costs

1,321,278

1,000,562

1,077,301

1,024,755

919,777








EBITDA

(48,095)

155,338

654,978

599,411

400,793







Capital Expenditures

118,577

435,154

558,313

306,371

250,926







EBITDA - Capex

(166,672)

(279,816)

96,666

293,040

149,866







Hedging Cash Impacts

194,701

-

-

-

-

Asset Sales

162,200

-

-

-

-

Midstream Cash Dividends

37,079

-

-

-

-

Equity Tax Payments

(26,546)

-

-

-

-

Capital Lease Payments

(17,474)

(6,787)

(6,778)

(6,778)

(6,797)

Other One-Time Items

(32,316)

(6,000)

-

-

-


Other Inflows / (Outflows)

317,643

(12,787)

(6,778)

(6,778)

(6,797)

Changes in Accounts Receivable

117,897

(5,845)

(36,294)

4,793

18,498

Changes in Tax Receivables

41,500

144,164

(20,371)

(8,792)

(9,522)

Changes in Inventory

(15,469)

2,578

(3,148)

904

2,546

Changes in Accounts Payable

(448,741)

91,802

57,800

(79,783)

(30,281)

One-Time Working Capital Impacts

(93,152)

-

-

-

-


Net Change in Working Capital

(397,965)

232,699

(2,014)

(82,878)

(18,759)







Cash Flow Before Restructuring Costs

(246,993)

(59,905)

87,874

203,383

124,310







Professional Fees

110,000

10,000

-

-

-


Restructuring Costs

110,000

10,000

-

-

-







Aggregate Cash Flow

(356,993)

(69,905)

87,874

203,383

124,310







DIP Draw / (Repayment)

206,993

69,905

(87,874)

(189,024)

-







Ending Cash Balance

100,000

100,000

100,000

114,359

238,669







Cumulative DIP Draw

206,993

276,898

189,024

-

-







Under the Strip + Consensus OBC 48 scenario, the maximum DIP draw in 2016 is $264.5 million, occurring in November 2016.

The Company has also prepared two additional cases limiting 2017 and 2018 development capital expenditures to $500 million. Both cases are based on the pricing assumptions outlined above.

Based upon the foregoing assumptions, among others, a summary of the Business Plan in the Base Case Reduced Capex OBC 48 scenario is set out below (note that the pricing in the Company's Base Case for the years 2016 and 2017 reflects a discount to the Brent Benchmark that causes the Base Case realized price to be lower than the Strip Case realized price for these years):


2016 – 2020 Annual

Period Ending

12/31/16

12/31/17

12/31/18

12/31/19

12/31/20

(all figures in USD thousands, unless otherwise stated)












Production (boed)

109,389

78,387

63,932

57,969

58,309

Average Realized Price ($/boe)

26.29

31.37

54.13

54.86

54.73

Discount to Brent Benchmark

4.99

5.32

10.82

12.24

12.96







Starting Cash Balance

$250,000

$100,000

$100,000

$100,000

$100,000








Total Revenues

1,087,450

938,580

1,327,654

1,227,538

1,235,516







Production & Operating Costs

1,125,848

821,498

716,673

650,276

669,896

SG&A Cost

167,000

140,000

140,000

140,000

140,000


Total Costs

1,292,848

961,498

856,673

790,276

809,896








EBITDA

(205,397)

(22,918)

470,981

437,262

425,620







Capital Expenditures

118,577

313,887

277,390

317,223

365,953







EBITDA - Capex

(323,974)

(336,805)

193,592

120,038

59,667







Hedging Cash Impacts

194,701

-

-

-

-

Asset Sales

162,200

-

-

-

-

Midstream Cash Dividends

37,079

-

-

-

-

Equity Tax Payments

(26,546)

-

-

-

-

Capital Lease Payments

(17,474)

(6,787)

(6,778)

(6,778)

(6,797)

Other One-Time Items

(32,316)

(6,000)

-

-

-


Other Inflows / (Outflows)

317,643

(12,787)

(6,778)

(6,778)

(6,797)

Changes in Accounts Receivable

126,377

(1,870)

(24,754)

4,734

(403)

Changes in Tax Receivables

41,500

147,811

(9,649)

(11,318)

(13,659)

Changes in Inventory

(15,440)

3,366

859

1,322

(430)

Changes in Accounts Payable

(449,232)

51,624

(10,771)

2,831

16,385

One-Time Working Capital Impacts

(93,152)

-

-

-

-


Net Change in Working Capital

(389,948)

200,932

(44,315)

(2,431)

1,893







Cash Flow Before Restructuring Costs

(396,799)

(148,661)

142,498

110,829

54,763







Professional Fees

110,000

10,000

-

-

-


Restructuring Costs

110,000

10,000

-

-

-







Aggregate Cash Flow

(506,279)

(158,661)

142,498

110,829

54,763







DIP Draw / (Repayment)

356,279

158,661

(142,498)

(110,829)

(54,763)







Ending Cash Balance

100,000

100,000

100,000

100,000

100,000







Cumulative DIP Draw

356,279

514,940

372,442

261,612

206,850

 

Under the Base Case Reduced Capex OBC 48 scenario, the maximum DIP draw in 2016 is $402.2 million, occurring in November 2016.

Based upon the foregoing assumptions, among others, a summary of the Business Plan in the Strip + Consensus Reduced Capex OBC 48 scenario is set out below:


2016 – 2020 Annual

Period Ending

12/31/16

12/31/17

12/31/18

12/31/19

12/31/20

(all figures in USD thousands, unless otherwise stated)












Production (boe/d)

109,389

78,387

63,932

57,969

58,309

Average Realized Price ($/boe)

30.93

36.91

54.13

54.86

54.73

Discount to Brent Benchmark ($/boe)

5.87

6.26

10.82

12.24

12.96







Starting Cash Balance

$250,000

$100,000

$100,000

$100,000

$182,513








Total Revenues

1,273,183

1,096,973

1,327,654

1,227,538

1,235,516







Production & Operating Costs

1,125,848

821,498

716,673

650,276

669,896

SG&A Cost

167,000

140,000

140,000

140,000

140,000


Total Costs

1,292,848

961,498

856,673

790,276

809,896








EBITDA

(19,665)

135,475

470,981

437,262

425,620







Capital Expenditures

118,577

313,887

277,390

317,223

365,953







EBITDA - Capex

(138,241)

(178,412)

193,592

120,038

59,667







Hedging Cash Impacts

194,701

-

-

-

-

Asset Sales

162,200

-

-

-

-

Midstream Cash Dividends

37,079

-

-

-

-

Equity Tax Payments

(26,546)

-

-

-

-

Capital Lease Payments

(17,474)

(6,787)

(6,778)

(6,778)

(6,797)

Other One-Time Items

(32,316)

(6,000)

-

-

-


Other Inflows / (Outflows)

317,643

(12,787)

(6,778)

(6,778)

(6,797)

Changes in Accounts Receivable

117,897

(2,200)

(15,945)

4,734

(403)

Changes in Tax Receivables

41,500

147,811

(9,649)

(11,318)

(13,659)

Changes in Inventory

(15,440)

3,366

859

1,322

(430)

Changes in Accounts Payable

(449,232)

51,624

(10,771)

2,831

16,385

One-Time Working Capital Impacts

(93,152)

-

-

-

-


Net Change in Working Capital

(398,428)

200,602

(35,506)

(2,431)

1,893







Cash Flow Before Restructuring Costs

(219,026)

9,402

151,307

110,829

54,763







Professional Fees

110,000

10,000

-

-

-


Restructuring Costs

110,000

10,000

-

-

-







Aggregate Cash Flow

(329,026)

(598)

151,307

110,829

54,763







DIP Draw / (Repayment)

179,026

598

(151,307)

(28,317)

-







Ending Cash Balance

100,000

100,000

100,000

182,513

237,275







Cumulative DIP Draw

179,026

179,624

28,317

-

-







 

Under the Strip + Consensus Reduced Capex OBC 48 scenario, the maximum DIP draw in 2016 is $237.0 million, occurring in November 2016.

About Pacific:

Pacific Exploration & Production Corp. 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 70 exploration and production blocks in various countries including Colombia, Peru, Guatemala, Brazil, Guyana and Belize. The Company's strategy is focused on sustainable growth in production & reserves and cash generation. Pacific Exploration & Production is committed to conducting business safely, in a socially and environmentally responsible manner.

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 and its strategy) 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: the Company's ability to continue as a going concern; volatility in market prices for oil and natural gas; a continued depressed oil price environment with a potential of further decline; default under the Company's credit facilities and/or the Company's senior notes due to a breach of covenants therein; amounts becoming due and payable under the credit facilities and/or the senior notes prior to voluntary insolvency proceedings, notwithstanding the entering into of such forbearance arrangements, whether through the actions of holders of senior notes or the trustee under the respective senior note indentures or otherwise; the impact of events of defaults in respect of the credit facilities and/or senior notes on other material contracts of the Company, including but not limited to, cross-defaults resulting in acceleration of amounts payable thereunder or the termination of such agreements; failure of the courts or other regulatory authorities to grant the protection sought by the Company under proceedings in Canada and/or proceedings under other applicable jurisdictions; failure of a sufficient number of supporting creditors entering into the support agreement; impact on the Restructuring Transaction or the operations of the Company in the event of an involuntary petition for bankruptcy relief or similar creditor action filed against the Company prior to the commencement of voluntary proceedings; failure of the Company to complete the Restructuring Transaction, which is subject to a number of conditions and other risks and uncertainties including, without limitation, court and required regulatory approvals or otherwise reach an agreement with its creditors or a sufficient number of them to restructure the Company's capital structure; failure to satisfy any terms or conditions of any other agreement with the Company's creditors on a proposed restructuring; any negative impact on the Company's current operations as a result of the Restructuring Transaction or any other proposed restructuring or failure to reach any other agreement with the creditors thereon; failure to satisfy the terms and conditions of any one of the Company's waiver agreements with applicable creditors or counterparties or any other waiver prior to voluntary insolvency proceedings, failure to obtain further extensions of any such waivers if required prior any voluntary insolvency proceedings, or failure to obtain waivers of other covenants prior to voluntary insolvency proceedings, if and when required; the terms of any such waivers, including the impact on the Company of any restrictions imposed upon it in connection with any waiver; 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 and/or has investments as the result of the entering into of the Restructuring Transaction or otherwise; expectations regarding the Company's ability to raise capital and to continually add to reserves through acquisitions and development; inability to continue meeting the listing requirements of the exchanges on which the Company's securities are listed due to the Restructuring Transaction; the cancellation or extensive dilution of the Company's equity securities as a result of the Restructuring Transaction; the effect of the Restructuring Transaction on the Company's business and operations; political developments in Colombia, Guatemala, Peru, Brazil, Guyana and Mexico; liabilities inherent in oil and gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions and/or past integration problems; geological, technical, drilling and processing problems; fluctuations in foreign exchange or interest rates and stock market volatility; delays in obtaining required environmental and other licenses; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; the possibility that actual circumstances will differ from estimates and assumptions; uncertainties relating to the availability and costs of financing needed in the future; changes in income tax laws or changes in tax laws, accounting principles and incentive programs relating to the oil and gas industry; and the other factors discussed under the heading entitled "Risk Factors" and elsewhere in the Company's AIF dated March 18, 2016 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.

Translation

This news release was prepared in the English language and subsequently translated into Spanish. In the case of any differences between the English version and its translated counterparts, the English document should be treated as the governing version.

Appendix A

See attached.

Appendix B

See attached.

SOURCE Pacific Exploration and Production Corporation

PDF available at: http://stream1.newswire.ca/media/2016/04/20/20160420_C1672_PDF_EN_671359.pdf

PDF available at: http://stream1.newswire.ca/media/2016/04/20/20160420_C1672_PDF_EN_671361.pdf

For further information: Frederick Kozak, Corporate Vice President, Investor Relations, +1 (403) 705-8816, +1 (403) 606-3165; Roberto Puente, Sr. Manager, Investor Relations, +57 (1) 511-2298, +507 (6) 205-1400; Richard Oyelowo, Manager, Investor Relations, +1 (416) 362-7735; MEDIA CONTACT: Tom Becker, Sitrick & Company, +1 (212) 573-6100

RELATED LINKS
http://www.pacific.energy

Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890