Frontera Energy Corporation (TSX: FEC) (OTCQX: FECCF) reported first-quarter 2026 net income from continuing operations of $13.1 million USD and adjusted EBITDA of $28.5 million USD, as the Calgary-based company moves to close the sale of its Colombian exploration and production portfolio to Parex Resources Inc. (TSX: PXT) and reposition itself as a standalone Colombian infrastructure company anchored by its pipeline and port assets.

Total revenues from continuing operations were $26.8 million USD in the first quarter, compared with $26.9 million USD in the fourth quarter of 2025 and $25.1 million USD in the first quarter of 2025. Net loss for the period, including discontinued operations, was $15.4 million USD, reflecting a $28.5 million USD net loss from the Colombian E&P assets now classified as held for sale.

“In total, this strategy will have unlocked approximately $1.3 billion of capital for investors.” — Gabriel de Alba, Chairman of the Board, Frontera Energy Corporation

The Parex transaction

On April 30, 2026, Frontera shareholders approved a plan of arrangement under which Parex Resources, through a wholly-owned subsidiary, will acquire all of Frontera’s Colombian upstream business — including its oil and gas exploration and production assets, a reverse-osmosis water-treatment facility, and a palm-oil plantation. The transaction carries an enterprise value of $750 million USD. The cash purchase price consists of $500 million USD payable at closing, subject to customary adjustments, plus an additional $25 million USD contingent payment tied to specified development milestones to be achieved within 12 months of closing.

At the same shareholder meeting, investors approved a reduction of Frontera’s capital account of up to $647 million CAD (approximately $470 million USD) to fund a return of capital to shareholders from the net proceeds of the transaction. The Supreme Court of British Columbia issued its final order approving the arrangement on May 4, 2026. Closing remains subject to the satisfaction of remaining conditions and is expected in May 2026.

Chairman Gabriel de Alba said the company would retain roughly $50 million USD of cash to support growth opportunities at the remaining infrastructure business, including an LNG regasification project being developed in partnership with Ecopetrol (NYSE: EC) (BVC: ECOPETROL). “In total, this strategy will have unlocked approximately $1.3 billion of capital for investors,” de Alba said.

ODL pipeline drives cash flow

Frontera holds a 35 percent equity interest in the Oleoducto de los Llanos (ODL) crude oil pipeline, which connects the Rubiales, Quifa, Caño Sur, Llanos-34, and other production blocks to the Monterrey and Cusiana stations in the department of Casanare. ODL’s share of income contributed $14.2 million USD to Frontera in the first quarter, compared with $15.1 million USD a year earlier, with the year-over-year decline reflecting higher depreciation, amortization, and operating costs.

ODL transported 233,875 barrels per day in the first quarter of 2026 at an average tariff of $4.70 USD per barrel, compared with 236,387 barrels per day at $4.73 USD per barrel in the first quarter of 2025. The pipeline declared $185 million USD in total dividends, of which $64.7 million USD is net to Frontera. The company expects to receive those distributions during 2026 in installments of approximately 40 percent in the second quarter, 35 percent in the third quarter, and 25 percent in the fourth quarter.

Long-term debt at Frontera totaled $167.8 million USD at the end of the first quarter and is expected to decline to approximately $131 million USD by year-end 2026, primarily through scheduled amortizations and cash-sweep mechanisms tied to ODL cash flows. From May 2025 through December 2026, long-term debt is expected to fall by more than $100 million USD.

Puerto Bahía expands cargo mix

Puerto Bahía, the multipurpose maritime terminal located in Cartagena adjacent to the Bocachica access channel and near the Reficar refinery, generated $12.7 million USD in revenue in the first quarter of 2026, compared with $10.0 million USD in the same period a year earlier. The 150-hectare facility comprises a hydrocarbons terminal with nominal capacity of 2,672,000 barrels and a general cargo terminal. Frontera holds a 99.97 percent equity interest in the port.

General cargo growth offset weaker liquids volumes. The general cargo terminal handled 38,067 roll-on/roll-off (RORO) units in the first quarter, more than double the 18,223 units handled a year earlier, alongside 3,851 twenty-foot equivalent units (TEUs) of containerized cargo, up from 1,256 TEUs in the first quarter of 2025. Break-bulk volumes declined to 25,216 tons/m³ from 41,198 tons/m³. RORO dwell times shortened from 40 days to 31 days year over year.

The liquids terminal handled 36,937 barrels per day in the first quarter of 2026, down from 51,579 barrels per day a year earlier. Ecopetrol volumes accounted for 26,273 barrels per day, Frontera-related volumes for 7,389 barrels per day, and other third-party volumes for 3,275 barrels per day. The company attributed the decline mainly to lower third-party throughput and the absence of certain trading flows.

Operating costs at the port rose to $7.6 million USD in the first quarter from $5.0 million USD a year earlier, driven by increased infrastructure maintenance in the liquids terminal and higher cargo volumes in the general cargo facility.

LPG and LNG projects advance

Puerto Bahía’s liquefied petroleum gas (LPG) project began initial operations in March 2026, providing capacity to handle up to 10,000 tons per month. The terminal is targeted to become fully operational during the first quarter of 2028. Capital expenditures during the first quarter totaled $1.0 million USD, including $0.4 million USD for major tank maintenance and $0.3 million USD for the LPG project.

The company is also advancing an LNG regasification project at Puerto Bahía in partnership with Ecopetrol, intended to support Colombia’s domestic gas supply as domestic production declines. Frontera is also pursuing expansion of containerized cargo operations.

Discontinued operations

Following the execution of the arrangement agreement, the Colombian E&P assets are now classified as discontinued operations under IFRS 5. Colombian production averaged 36,700 barrels of oil equivalent per day in the first quarter of 2026, comprising 25,394 barrels per day of heavy crude, 8,653 barrels per day of light and medium crude combined, 5,706 thousand cubic feet per day of conventional natural gas, and 1,652 barrels of oil equivalent per day of natural gas liquids. That compares with 39,010 barrels of oil equivalent per day a year earlier.

The operating netback from the discontinued Colombian operations was $41.79 USD per barrel of oil equivalent in the first quarter of 2026, compared with $34.22 USD per barrel of oil equivalent in the first quarter of 2025, supported by a higher Brent reference price of $78.38 USD per barrel against $74.98 USD per barrel a year earlier.

Frontera retains exploration and development interests in Guyana through subsidiaries that include CGX Energy Inc. (TSXV: OYL), which is not part of the Parex transaction. The company’s go-forward portfolio will be anchored by the ODL pipeline stake and Puerto Bahía, with the infrastructure business generating approximately $77 million USD of distributable cash flow in 2025, according to the management information circular dated March 30, 2026.

Above photo courtesy Frontera Energy Corporation.

The company’s average reserve life now sits at 7.6 years, with a reserve replacement ratio (RRR) of 48%. Proven developed reserves also grew roughly 4% compared to 2022, which Ecopetrol credits to improved execution capacity.

While citing a difficult climate that saw per-barrel prices of Brent crude drop from an average of $99 USD in 2022 to just $82 USD in 2023, the company highlighted its ability to benefit from global production cuts.

“Ecopetrol’s commercial strategy capitalized on increased demand for our crude oils due to OPEC+ production cuts and limitations in Canadian crude supply,” the company stated its reserves report. “Simultaneously, differentials for our refined products remained strong compared to historical levels, allowing us to leverage the growth in our refinery capacity.

Ecopetrol Reserves & Production

In its statement, Ecopetrol added the following details about its reserves and production: “An organic incorporation of 307 MBPE was achieved in 2023, which represented a 43% increase as compared to the organic incorporation in 2022, mainly as a result of new projects, better forecasts of production fields, increased prospects for enhanced recovery, extensions and discoveries.”

“However, the incorporation of reserves decreased by 188 MBPE, as a result of economic factors such as the fall in the Brent crude oil price and inflationary effects, as well as changes in technical conditions, mainly, water intrusion, in fields such as Ballena, Cupiagua and Recetor. The above resulted in a positive net incorporation of 119 MBPE.”

Ecopetrol also noted that 93 MBPE of the reserves incorporated last year came from “better capacity for execution and implementation of improved recovery expansion projects” in fields including Chichimene, Castilla, and Akacias.

“In addition, fields such as Cano Sur and Rubiales presented positive reserve revisions due to good production performance and new drilling projects to implement in the future,” added Ecopetrol.

Overall, 78% of the proven reserves are liquid reserves with 22% being gas reserves.

Geographically, 89% of proven reserves — which includes all the crude oil, condensate, and natural gas of the company, its affiliates, and subsidiaries — are located in Colombia with the remaining 11% in the United States.

(Photo credit: Ecopetrol)

By the end of 2020, the Ecopetrol Group’s net proven reserves totalled 1,770 million barrels of oil equivalent (MBOE), which represents a 6.5% decrease versus 2019 (1,893 MBOE). The reserves replacement ratio was 48%, with an average reserve life of 7.5 years. Gas reserves represented 29% of this volume, with an average reserve life of 10.1 years, while liquids reserves represented the remaining 71%, with an average reserve life of 6.8 years.

The reduction in proven reserves was mainly due to the 32% decrease in hydrocarbon prices used for the valuation. According to the SEC methodology, the Brent price used for the 2020 valuation of reserves was US$43 per Brent barrel, versus US$63 used for 2019. Ecopetrol estimates that the price effect led to a decrease in reserves of 215 MBOE, which was partially offset by the addition of 114 MBOE attributable to new drilling projects in different fields, such as Rubiales and Caño Sur. Additionally, positive revisions of 30 MBOE were obtained due to the good performance in production and optimization of technical-economic variables in fields such as Rubiales, Castilla and other fields in North America.

In terms of enhanced recovery, there was a positive variation of 113 MBOE, primarily due to the incorporation of reserves from new projects mainly associated with water injection in fields such as Chichimene and Castilla.

Additionally, in extensions and discoveries, progress continues to be made in the progression of probable and possible reserves to proven reserves in the Rubiales field, primarily due to the continuity of drilling operations, among others. As for discoveries, the ESOX field in the Gulf of Mexico and the Andina field in Colombia achieved commercial viability.

Sales include Hocol’s interest transfer in La Punta and Santo Domingo fields for a value of 1 MBOE.  Purchases include 29.9 MBOE corresponding to the acquisition of 43% of the Guajira asset by Hocol.

The largest contributions to the reserves balance came from the Castilla, Chichimene, and Rubiales fields, which are operated directly by Ecopetrol.

Ecopetrol S.A. owns 85% of the proven reserves, while the other group companies own 15%.

Frontera Energy will primarily use the cash received from the sale as an initial payment in a previously announced agreement to acquire International Finance Corporation’s (IFC) shares in Pacific Midstream Limited. The deal to buy the 36.36%interest held by IFC, and related parties, was agreed to earlier this month for a total of $225 million USD and will give Frontera Energy full control over Pacific Midstream Limited.

According to the company, $50 million USD of the incoming $56 million USD in proceeds will be used in the first payment to IFC. Frontera has up to 36 months to pay off the full sum, plus accrued interest.

Gabriel de Alba, chairman of Frontera Energy, which was previously known as Pacific Rubiales, called the move to fully acquire Pacific Midstream a “very strategic acquisition” that will support the firm’s push “to reduce our corporate transportation costs, provide long-term transportation flexibility, and reduce fixed-cost transportation obligations.”

He says both deals align with the company’s ongoing strategy to sell off non-core assets in favor of “more strategic initiatives while maintaining a strong cash position on our balance sheet.”

In the past 12 months, Frontera Energy has now secured nearly $150 million USD in cash from asset sales. These sales, according to the company, have also resulted in a roughly $147 million USD “reduction in exploration or environmental commitments” and the elimination of around $52 million in “stand-by letters of credit commitments.”

A key asset of Petroelectrica de los Llanos is its 260-kilometer power transmission line, with 192 megawatts of authorized electricity demand, that supplies power to the both the Rubiales and Quifa oil fields as well as the Oleoducto de los Llanos pipeline.

The company expects to begin trading common shares under the name Frontera, which means “border” or “frontier” in Spanish, on the Toronto Stock Exchange, under the ticker symbol TSX:FEC, beginning tomorrow, June 14. It’s corporate website has already been moved from to www.Pacific.Energy to www.FronteraEnergy.ca.

In addition to its headquarters in Toronto and Canadian location in Calgary, the company has an office in Bogotá and Lima, Peru. On top of other financial and operational challenges, the company was dealt a large blow last year when, due to the expiration of a long-held contract, it was forced to relinquish to state-controlled oil company Ecopetrol its large holding in Colombia’s Rubiales oilfield, the largest and most productive in the country.

In 2015, after Ecopetrol announced its decision to take full control of the Rubiales field, the company changed its name from Pacific Rubiales to Pacific Exploration & Production Company. The change to Frontera Energy thus marks its second rebranding move in the past 22 months.

Barry Larson, who took over in January as chief executive officer of Frontera Energy Corporation, said that the change reflects the company’s new commitment to efficiency, discipline, a limited geographic focus, and the firm’s core values.

“Our new corporate identity reflects the significant transformation the company has made following its restructuring, as well as a new progressive and disciplined focus that will generate success,” said Larson today in a statement. “To ensure the company can maintain sustainable production and growth, the board has taken steps to narrow Frontera’s geographic focus and reduce organizational scale, complexity, and cost while maximizing operating and cost efficiencies.”

Frontera Energy has detailed four specific principles that it now plans to build around as it recovers from past hurdles and missteps: (1) successful debt restructuring focused on discipline growth, (2) an ongoing turnaround aimed at optimizing the corporate structure to realize savings, improve margins, and create operating efficiencies, (3) prioritizing production growth and exploration upside, particularly through development drilling in highly prospective areas, and (4) unlocking value through a divestment strategy that attempts to improve liquidity and capture the potential of high-value infrastructure assets.

The state-controlled oil giant already increased its production by 3.9% this quarter over the second quarter — to hit 723,000 barrels of oil equivalent per day — and that is only set to grow further, said Ecopetrol CEO Juan Carlos Echeverry.

“The group has overcome the period of low oil prices and has returned to the path of growth in production,” said Echeverry. He added that, “Ecopetrol has an optimistic view of the future.”

Financial Results

The Ecopetrol Group reported an EBITDA of 4.9 trillion Colombian pesos ($1.55 billion USD) and an EBITDA margin of 40% in the third quarter. Net profit attributable to Ecopetrol shareholders in the third quarter rose to COP 229 billion pesos ($72.6 million), per the company.

In terms of EBITDA and EBITDA margin, this was the best showing in the last five quarters for Ecopetrol. Echeverry credits the success to rising crude prices, austerity measures implemented earlier this year, capital discipline, and better efficiency. “This good result demonstrates our commitment to operational excellence, cost efficiency, and capital discipline,” said the chief executive.

The results and capital situation have improved enough this year that Ecopetrol opted to pay off a $340 million USD loan from Bancolombia early. The funds weren’t due until 2024, but its prepayment last month”was made possible by the solid cash position of the company as a result of cost efficiencies,” said Ecopetrol in a statement.

Market Response

The market response to the news has been active. More than 650,000 Ecopetrol shares traded hands yesterday, according to the Press Telegraph, and it has gained a bit of steam on the New York Stock Exchange.

The uptick since the results were publicized has added to a minor rally in the lead up to the announcement that has taken the share price from $7.69 USD on November 11 to $8.22 in mid-day trading today.

Shares for the beleaguered firm remain well below their 2016 high of $10.00 seen in mid-July, which followed a bottoming out in January 20 of just $5.40. At the company’s soaring heights in mid-2013, shares were trading at more than $63 on the New York Stock Exchange.

Production Increases

A big win for Ecopetrol’s results this year was its takeover of the Rubiales field, the largest oil-producing area in Colombia. In a move announced in the summer of 2015, it officially ended its long-time partnership with Pacific Exploration & Production Corporation this July to assume a 100% holding in the lucrative field.

Some questioned whether the transition would be seamless and if Ecopetrol would be able to pull the same margins as it assumed all operating responsibility. Production at the site has dropped — but only slightly — so thus far, Echeverry says he has been pleased with the results.

“Although during the quarter the production of the field continued to decline from 138,000 barrels per day to 127,000 barrels per day, it’s noteworthy that the challenge of resuming the 100% of the operation was successful,” stated Bancolombia in a note to investors. “The declines reported are due in part to the few investments made during the first half by its former operator.”

Production also began this year at the Gunflint site in the Gulf of Mexico, where Ecopetrol has a partial stake in what is expected to become one of the best holdings for its Ecopetrol Americas subsidiary. “We’ve started to reap the benefits of investments made in previous years,” said Echeverry of the Gunflint project.

Additionally, the company commenced in the startup of 34 units at the Cartagena refinery in July, when it “initiated the stabilization and performance testing period,” said Echeverry.

In a conference call, it elaborated on its expansion plans going forward. “The company indicated that during the remainder of the year and during 2017 it will continue exploration activity both offshore and onshore,” stated Bancolombia. “In the short term, drilling of appraisal wells is expected in search of a better understanding of the reservoir around the already announced exploratory success at Kronos. Also important will be the drilling of the Molusco well, the first 100% offshore well held by Ecopetrol, where work would begin towards the third quarter of 2017.”

“The company has made submissions to the Superintendence in respect of this lien and is waiting for a decision,” said Pacific Exploration in a statement. “The company will issue a further news release at such time as the decision is made in order to confirm timing of closing of the [Catalyst] restructuring.”

This represents at least the second unexpected delay this month for Pacific Exploration. In September, it projected to close on the Catalyst plan during the week of October 3. When that proved overly optimistic, the company said that its agreement with Catalyst Capital would close on October 12, “assuming satisfaction or waiver of the remaining conditions, including finalization of negotiations with respect to certain pending matters.”

This hold up with the Superintendence was apparently one of those pending matters that the company expected to be complete at least 10 days ago. Pacific Exploration is quick to assure the market that this delay should not affect any aspects of the already-announced details of its recapitalization plan with Catalyst.

“The company confirms that the share or cash distributions under the plan as set out in the company’s news release of September 26, 2016 remain unchanged,” said Pacific Exploration. “The Toronto Stock Exchange has conditionally approved the listing of the company’s common shares upon implementation” of the [restructuring].”

That Pacific Exploration press release from September 26 is reprinted in full here:

Pacific Exploration & Production Corp. (the “Company”) is pleased to provide an update with respect to its previously announced plan of compromise and arrangement (the “Plan”) pursuant to the Companies’ Creditors Arrangement Act (Canada) in connection with its comprehensive restructuring transaction (the “Creditor/Catalyst Restructuring Transaction”).

To date, the Company has received and approved claims affected by the Creditor/Catalyst Restructuring Transaction in the amount of US$5,502,869,874 (the “Affected Claims”) consisting of US$4,254,956,647 of claims from holders (the “Noteholders”) of the Company’s senior unsecured notes (the “Notes”), US$1,232,627,877 of claims from lenders (the “Bank Lenders”) under the Company’s credit facilities and US$15,285,350 of claims from other creditors affected by the Plan (the “Other Affected Creditors” and, together with the Noteholders and Bank Lenders, the “Affected Creditors”). The amount of claims of Other Affected Creditors continues to be finalized and therefore the total amount of Affected Claims, and the distribution to Affected Creditors, is subject to change.

Under the Plan, Affected Creditors are entitled to receive their pro rata share of approximately 29,100,000 common shares of the Company (after giving effect to the share consolidation contemplated by the Plan, the “Affected Creditor Shares”) representing approximately 58.2% of the fully diluted common shares of the reorganized Company; provided that, subject to certain terms and conditions, Noteholders who signed and returned the Support Agreement in respect of the Creditor/Catalyst Restructuring Transaction, submitted a valid Application for Early Consent Consideration and otherwise complied with the terms of the Plan (“Early Consent Noteholders”) are entitled to receive, as additional consideration in exchange for their Affected Claims, their pro rata share of approximately 2.2% of the fully diluted common shares of the reorganized Company. This amount is to be allocated from the Affected Creditor Shares otherwise payable to the Noteholders.

In addition, Affected Creditors were entitled, subject to certain terms and conditions, to elect to receive, in lieu of their Affected Creditor Shares, cash at either a “Designated Rate” of US$16.00 per Affected Creditor Share (on a post consolidation basis) or, if accepted, such other “Offer Rate” above US$16.00 per Affected Creditor Share (on a post consolidation basis) that they could designate in US$0.10 increments (the “Cash Election”). Offer Rates up to and including US$26.00 per Affected Creditor Share (on a post consolidation basis) were ultimately accepted (the Designated Rate and such accepted Offer Rates, the “Acceptable Cash Rates”). For greater certainty, if an Affected Creditor designated an Offer Rate of US$26.10 or greater, they will not be receiving cash but will receive their proportion of Affected Creditor Shares.

Under the terms of the Plan, The Catalyst Capital Group Inc. (the “Plan Sponsor”) and certain other Noteholders (the “Equity Subscribers”) were required to subscribe for shares in the capital of the Company in order to fund the Cash Election at Acceptable Cash Rates.

Accordingly, subject to finalization of the Affected Claims, the Company expects that the Affected Creditor Shares or cash in lieu thereof pursuant to the Cash Election will be issued to Affected Creditors as follows:

Noteholders (Excluding any Early Consent Consideration)

Noteholders will receive for every US$100,000 of principal amount, in addition to any Early Consent Consideration they may be entitled to, either:

It is anticipated that such Affected Creditor Shares, or cash in lieu thereof, will be delivered through the facilities of The Depository Trust Company to each Noteholder’s intermediaries (such as the bank, broker or other intermediary that holds Notes on behalf of a Noteholder, herein referred to as an “Intermediary”) who in turn will deliver such Affected Creditor Shares or cash, as applicable, to the Noteholders pursuant to standing instructions and customary practices.

Noteholders Receiving Early Consent Consideration

In addition to any Affected Creditor Shares or cash in lieu thereof they would otherwise receive in their capacity as a Noteholder, Early Consent Noteholders will also receive for every US$100,000 of principal amount either:

It is anticipated that, pursuant to the instructions provided by a Noteholder in its Application for Early Consent Consideration, such Affected Creditor Shares will be delivered to such Noteholder (or its Intermediary) by Direct Registration System Advices and cash in lieu thereof will be delivered to such Noteholder (or its Intermediary) by wire transfer or cheque.

Bank Lenders and Other Affected Creditors

Bank Lenders and Other Affected Creditors will receive approximately 528.81 Affected Creditor Shares for every US$100,000 of Affected Claims or, if they validly participated in the Cash Election at an Acceptable Cash Rate, cash in an amount approximately equal to such creditor’s Applicable Cash Rate multiplied by such factor.

It is anticipated that, pursuant to instructions provided by a Bank Lender or Other Affected Creditor to PricewaterhouseCoopers Inc. (as monitor under the Plan), such Affected Creditor Shares will be delivered to such Bank Lender or Other Affected Creditor in certificated form and cash in lieu thereof will be delivered to such Bank Lender or Other Affected Creditor by wire transfer or cheque.

Subject to finalization of the Affected Claims, Affected Creditors have, pursuant to the Cash Election, validly elected to receive cash in the amount of approximately US$16,317,446 in lieu of approximately 925,619 Affected Creditor Shares and, accordingly, the Plan Sponsor and Equity Subscribers will subscribe for such number of shares to fund such amount.

In addition to the Affected Creditor Shares, the Company expects:

• to issue to holders of warrants (which warrants are exercised under the Plan) issued as part of the debtor-in-possession financing in connection with the Creditor/Catalyst Restructuring Transaction Financing (the “DIP Financing”), 6,250,000 common shares of the Company (after giving effect to the share consolidation contemplated by the Plan) representing approximately 12.5% of the fully diluted common shares of the reorganized Company;

• that the US$250 million (less an original issue discount) of funding provided by the Plan Sponsor as part of the DIP Financing will be exchanged for 14,650,000 common shares of the reorganized Company, representing approximately 29.3% of the fully diluted common shares of the reorganized Company; and

• that its common shares will be, in accordance with the terms of the Plan, consolidated on the basis of one post-consolidated share for each 100,000 common shares of the Company outstanding immediately prior to implementation of the Plan and any fractional common shares will be rounded down to the nearest whole number without consideration in respect thereof. Accordingly every person that holds fewer than 100,000 common shares of the Company will cease to be a shareholder of the Company following the implementation of the Plan.

The amount of Affected Claims continues to be finalized and therefore, notwithstanding anything contained herein, the distributions to Affected Creditors as set out in this press release are subject to change. We also caution that, owing to rounding, the number of Affected Creditor Shares or cash in lieu thereof actually received by Affected Creditors may not match the factors set out herein.

Shareholder Contact Information

Shareholders are reminded that any questions or concerns can be directed to the Company at ir@pacificcorp.energy.

Noteholder Contact Information

Noteholders with questions about the Plan are encouraged to contact Kingsdale Shareholder Services at 1-877-659-1821 toll-free in North America or call collect at 1-416-867-2272 outside of North America or by email at contactus@kingsdaleshareholder.com.

In a statement, Pacific Exploration said its agreement with Catalyst Capital will close on October 12, “assuming satisfaction or waiver of the remaining conditions, including finalization of negotiations with respect to certain pending matters.”

Despite that caveat, the company also says it “confirms that the share or cash distributions under the plan, as set out in the company’s press release of September 26, 2016, remain unchanged.”

As first reported in April by Reuters, the arrangement is expected to clear around $5 billion USD of debt and more than $250 million USD in annual interest costs off of Pacific Exploration’s books. The company said Catalyst Capital, among other creditors, will inject some $500 million USD of debtor-in-possession financing.

The restructuring plan with Catalyst Capital was negotiated despite “strong opposition from some Pacific shareholders who argued the deal favors management over investors,” according to a Wall Street Journal report in April.

Pacific Exploration entered creditor protection the same month after filing with the Superior Court of Justice in Ontario, Canada. Prior to the filing, it had failed to make bond interest payments in both January and March.

The falling price of oil — on top of being forced to turn over control of Colombia’s lucrative Rubiales oilfield to the state-controlled Ecopetrol — has left the firm reeling in recent years with few options to meet payments on its debt. The company was known as Pacific Rubiales Energy Corp. before Ecopetrol decided not to renew a contract that would allow the Canadian firm to continue overseeing production at the nation’s largest oilfield. It rebranded soon after.

CEO Ronald Pantin defended the company in a statement: “Contrary to market rumours, the Company is not in default under any of its debt obligations and does not expect to be at risk of payment default. The leverage covenants in our senior  notes are ‘incurrence based covenants’ which simply means the Company’s ability to take on additional debt may be restricted by such ratios, subject to various exemptions. All of our senior notes have maturities that extend out from 2019 to 2025.”

Pantin went on to describe aggressive cost cutting that the company is undertaking immediately in order to weather the current market conditions. “The uncertainty in oil prices continues and although we believe that oil prices will recover, we are taking a cautious view on the timing, reducing both our costs and our 2015 capital budget to match expected cash flow. The Company has the operational and financial flexibility to adapt to the changing environment while continuing to grow production. Our reduced capital budget only has a marginal impact on production targets as we focus expenditures on our highest return and most material near-term projects.”

“Pacific Rubiales remains fully focused on maintaining liquidity in this environment, by significantly reducing costs and also reducing capital expenditures by $200 to $400 million, to match expected cash flow. Furthermore, we have additional flexibility from our $1.0 billion revolving credit facility, which is currently undrawn,” said Pantin. “Reducing costs remains a priority. Our cash operating costs are now expected to be approximately $28/boe (barrel of oil equivalent), benefiting from the lower Colombian Peso, a number of cost reduction initiatives put in place before year-end 2014, and lower supplier service costs. We expect significantly lower G&A costs to be driven by the lower local currency exchange rate and a reduction in staff and other costs. Average royalty rates and cash taxes are also expected to be reduced in the lower oil price environment.”

The debts were incurred partly through a string of acquisitions in the recent past, when oil production was more lucrative. The Canadian based but South America focused producer of natural gas and crude oil, owns 100% of Meta Petroleum Corp. , which operates the Rubiales, Piriri and Quifa heavy oil fields in the Llanos Basin, and 100% of Pacific Stratus Energy Colombia Corp., which operates the La Creciente natural gas field in the northwestern area of Colombia.  Pacific Rubiales has also previously acquired 100% of Petrominerales Ltd, which owns light and heavy oil assets in Colombia and oil and gas assets in Peru, 100% of PetroMagdalena Energy Corp., which owns light oil assets in Colombia, and 100% of C&C Energia Ltd., which owns light oil assets in the Llanos Basin.  In addition, the Company has a diversified portfolio of assets beyond Colombia, which includes producing and exploration assets in Peru, Guatemala, Brazil, Guyana and Papua New Guinea.

2015 Revised Guidance – Key Highlights released by Pacific Rubiales:

• Net production of 150 to 160 Mboe/d, a slight decrease from the previous guidance, representing approximately 1 to 8% growth over expected 2014 production levels.

• Average WTI oil price assumption of $55 to $60/bbl during the year.

• Oil price realization is expected to be $1 to $2 above the WTI benchmark price assumption.

• A significant reduction in 2015 cash costs: with operating costs estimated at $28/boe, G&A costs of $200 million, financing costs of $250 million and cash taxes of $200 million expected.

• Generating Adjusted EBITDA of $1.5 to $1.7 billion (including funds from hedging programs and dividends from affiliates), and Funds Flow (Cash Flow) of $1.1 to $1.3 billion.

• Exploration and development (“E&D“) capital expenditures of $1.1 to $1.3 billion, the majority directed to development drilling and facilities, and a small amount to exploration.

The company’s common shares trade on the Toronto Stock Exchange and La Bolsa de Valores de Colombia and as Brazilian Depositary Receipts on Brazil’s Bolsa de Valores Mercadorias e Futuros under the ticker symbols PRE, PREC, and PREB, respectively.