The Energy Bulletin Weekly: 15 June 2020 - Resilience

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The Energy Bulletin Weekly: 15 June 2020 - ResilienceThe Energy Bulletin Weekly: 15 June 2020 - ResiliencePosted: 15 Jun 2020 12:00 AM PDTTom Whipple and Steve Andrews, EditorsQuotes of the Week"Losses this year will be the biggest in aviation history. There is no comparison for the dimensions of this crisis." Alexandre de Juniac, Int'l Air Transportation Assoc.'s CEO"It remains unclear if oil demand will ever return to pre-pandemic levels. From the destruction of the aviation industry to the transformation of workplace dynamics reducing daily travel and governmental pushes for renewable energy, oil demand is being attacked on all sides due to COVID-19. The oil majors seem to have recognized this global shift and are determined to make their operations as lean and sustainable as possible. 2020 is shaping up to be the most dramatic year in the history of oil markets, with a decade's worth of change seeming to be taking place in just 365 days." Charles Ke…

Is Big Oil Immune To The Coronavirus - OilPrice.com

Is Big Oil Immune To The Coronavirus - OilPrice.com


Is Big Oil Immune To The Coronavirus - OilPrice.com

Posted: 05 Mar 2020 03:00 PM PST

With and gas prices remaining stubbornly low despite a flurry of supply chain disruptions that can potentially offer support, there's seemingly little to cheer about in this market. Oil and gas prices have remained grounded for months now despite long-term U.S. sanctions on oil flows out of Iran, production cuts by OPEC+ and a blockade in Libya with no end in sight--all of which add up to a sizable 6% loss of global supply. 

At the same time, the COVID-19 pandemic has crushed the demand side, with the International Energy Agency (IEA) last month slashing its 2020 oil demand growth forecast by 365,000 bpd to 825,000 bpd. Oil and gas prices have responded strongly to the expected lower demand and not to the supply disruptions--a clear sign that the coronavirus outbreak is far outweighing even unprecedented declines in supply.

Several pundits, however, remain sanguine that Big Oil has got enough gas in the tank to weather the ongoing storm.

A cross-section of analysts believe that the oil majors are in good shape to ride out the short-term impact of the coronavirus outbreak without significant changes to their long-term investment roadmap.

Long-term bullish

In the bulls' camp is S&P Global Platts Analytics, which has opined that a decrease in oil demand wrought by the coronavirus is unlikely to have a major impact on global E&P spending. Indeed, the research firm notes that U.S. shale production--the biggest source of crude and condensate supply growth in 2020--is unlikely to be affected since most operators have based their 2020 forecasts on an average WTI price of $50/barrel. Similarly, the analysts expect activity in offshore areas including Gulf of Mexico, Guyana, Brazil and in the North Sea to remain unaffected due to the long lead-time nature of such projects.

Interestingly, analysts at Jefferies share more or less a similar view, despite recently throwing in the towel on the sector. Related: OPEC Slashes Oil Demand Growth Forecast To 480,000 Bpd

"We are at the cash flow neutrality level," Jefferies analyst Jason Gammel has said, adding that while big oil companies will be cautious due to the coronavirus-induced drop in prices, they won't be changing plans. Gammel, however, has cautioned that a prolonged multi-month price fall below $50/b could affect short-term projects--especially shale.

On Wednesday, Jefferies declared, "Energy is the new '62 Mets," likening the sector to the worst team in major league baseball history. You can hardly blame them for that take, with the S&P 500 Energy sector being the only sector in U.S. equity markets that's going through an outright bear market. Dow Jones Market Data shows the sector was down 33.11% from its recent high as of Tuesday, marking the sector's third worst bear market.

Cash flow crunch

Energy consultancy firm Wood Mackenzie believes that the biggest threat to the oil majors by the coronavirus outbreak is a potential cash flow crunch rather than potential supply chain hiccups. Mackenzie notes that a $10/barrel change in oil prices has a $40 billion impact on global cash flow per quarter for the sector, which potentially means negative cash flows and lower shareholder distributions if commodity prices remain depressed.

However, Evercore ISI and Norwegian energy consultancy, Rystad Energy, are less sanguine.

Evercore analyst James West says that the company's annual 2020 E&P upstream spending survey found that most upstream operators budgeted at $58/barrel, something the company has labeled 'disconcerting.' It certainly appears so considering that it's well below the current Brent price of $51.31/barrel and also when taking into account that prices have remained below that level for seven straight weeks. On a brighter note, Evercore sees WTI price below $47 (current price at $47.07/barrel) as the tipping point where most E&Ps would reduce their budgets.

Rystad Energy is even more downbeat. The firm sees U.S. shale drillers being hardest hit, especially if the upcoming OPEC and non-OPEC meeting in Vienna fails to yield the desired results. In a chilling note, Rystad sees the COVID-19 outbreak lowering global E&P investments by $30 billion in 2020.

Big oil in good shape

So, what are the oil majors saying about the situation?

Apparently, many remain upbeat and expect little or no changes to their earlier projections. Related: Has U.S. Electricity Lost Its Spark?

BP is one oil major that appears resilient enough to handle a sharper price fall. The company's new CEO, Bernard Looney, says BP, like many of its peers, has high-graded many of its upstream projects:

"BP is in excellent shape. We have invested a lot of money over the last several years in 35 major projects," Bernard Looney declared in February, adding that 23 of these were now online. CFO Brian Gilvary said sees 2020 breakeven around mid-$50s while Looney says 2021 breakeven will be even lower at around $40/barrel.

ExxonMobil says it's sticking to its new playbook of investing counter-cyclically and will therefore stick to earlier plans to spend between $33 billion and $35 billion this year. Analysts see the company with cash flow breakevens close to $50/barrel.

Meanwhile, Shell has based its future earnings targets on a rather high Brent oil price of $60/barrel, underpinned by its newer lower-cost upstream oil and gas projects. However, it sees its average upstream breakeven falling to just $30/barrel from about $40/barrel currently.

Total CEO Patrick Pouyanne says production discipline is key with the company echoing the new industry mantra of ''not volume growth but value growth.'' 

Overall, it appears that long-term investments by the oil majors are unlikely to be affected in a major way unless the outbreak throws a really big curveball. That said, it's still quite likely that investors will see a new round of dividend cuts or--at the very least--scaling back on buybacks as Mackenzie has warned.

By Alex Kimani for Oilprice.com

More Top Reads From Oilprice.com:

Crude In Focus After OPEC Agrees on Supply Cut to Offset Coronavirus Impact - Nasdaq

Posted: 05 Mar 2020 06:15 AM PST

SECTOR COMMENTARY

The energy sector is poised for a lower start, pressured by weakness in the crude complex and major equity futures which dropped on fresh virus fears after California declared an emergency. Sector news today was dominated by a handful of earnings from the producers and headlines coming out of Exxon's analyst day.

WTI and Brent crude oil futures extended yesterday's declines into this morning session, weighed down by the intensifying coronavirus fears that are impacting the equity markets and which offset news that OPEC agreed to cut oil output by an extra 1.5 million bpd in the second quarter of 2020 to help support prices. The group however stipulated that the action was conditional on Russia and others joining in.

Natural gas futures dipped lower this morning following three-consecutive days of gains, falling ahead of the weekly storage report later this morning and amid mild weather forecasts.

U.S. INTEGRATEDS

Reuters - Exxon Mobil hosted its analyst day and said it would stick to its spending plans. The Chief Executive Officer Darren Woods said the company would spend between $30 billion and $35 billion a year through 2025 and forecast $33 billion in capital expenditure this year.

INTERNATIONAL INTEGRATEDS

Reuters - Eni has made no decision or announcement about a potential closure of the Milazzo refinery in Sicily, a spokeswoman said on Thursday. A media report earlier on Thursday, citing Eni officials, said the plant would close due to air quality regulations the facility was unable to achieve in time. The report said closure was planned by January 1, 2022. "Milazzo Refinery itself, together with the other Sicilian refining operators, has formally appealed against the new environmental limits," Eni said. Milazzo refinery is operated through a joint-venture between Eni and Kuwait Petroleum Italy.

(Late Wednesday) Press Release - Mexico's private sector has drawn up a broad package of proposed energy investments for the government worth almost $92 billion, according to a document seen by Reuters on Wednesday, providing a potential lift to the country's misfiring economy. With 275 projects from 2020 to 2024 encompassing everything from power generation, storage and transportation to exploration and production of natural gas, the 1.787 trillion peso ($91.5 billion) package could significantly influence the government's national energy plan, which is due to be presented soon. The projects sketched out were the product of discussions between Mexico's business coordinating council (CCE) and dozens of energy companies, including Royal Dutch Shell, Mexico's IEnova, a unit of Sempra Energy, France's Engie and Italy's Enel, the document showed.       

U.S. E&PS

(Late Wednesday) Press release - Apache Corporation today announced details regarding its new organizational structure and key leadership roles. As announced in October 2019, the company has undertaken a comprehensive redesign of its organizational structure and operations to further align its work processes and cost structure with long-term planned activity levels.

Press Release - ConocoPhillips announced the completion of two transactions to sell its Niobrara and Waddell Ranch assets to undisclosed buyers. The Niobrara assets are located in the southern Denver-Julesburg Basin. Full-year 2019 production associated with the Niobrara assets was 11 thousand barrels of oil equivalent per day (MBOED). The effective date of the transaction is June 1, 2019. The Waddell Ranch conventional assets are located in the Permian Basin. Full-year 2019 production associated with the Waddell Ranch assets was 4 MBOED. The effective date of the transaction is Nov. 1, 2019. There is no change to the company's guidance items as a result of these transactions.

(Late Wednesday) Press Release - The Board of Directors of Hess declared a regular quarterly dividend of 25 cents per share payable on the Common Stock of the Corporation on March 30, 2020 to holders of record at the close of business on March 16, 2020.

(Late Wednesday) Press Release - W&T Offshore reported operational and financial results for the fourth quarter and full year 2019 including the Company's year-end 2019 reserves report and 2020 production and expense guidance. W&T also announced it will be acquiring the remaining 25% working interest in the Magnolia Field in early 2020. For the fourth quarter of 2019, W&T reported net income of $9.6 million, or $0.07 per share.  Excluding primarily an $18.1 million unrealized commodity derivative loss, the Company's Adjusted Net Income was $24.4 million, or $0.17 per share. In the fourth quarter of 2018, W&T reported net income of $138.8 million, or $0.96 per share, which included a $47.1 million non-cash gain on debt refinancing. Adjusted Net Income for the fourth quarter of 2018 was $34.2 million or $0.24 per share. Production for the fourth quarter of 2019 was 52,773 Boe/d or 4.9 MMBoe, an increase of 28% compared to 41,149 Boe/d in the third quarter of 2019 and up 51% versus 35,000 Boe/d in the fourth quarter of 2018.  Production for the fourth quarter of 2019 was above the mid-point of production guidance.  Fourth quarter 2019 production was comprised of 1.8 million barrels of oil, 0.4 MMBbls of natural gas liquids and 16.0 billion cubic feet of natural gas.  Liquids production comprised 45% of total production in the fourth quarter of 2019.  For the fourth quarter of 2019, W&T's average realized crude oil sales price was $56.84 per barrel. The Company's realized NGL sales price was $16.64 per barrel and its realized natural gas sales price was $2.58 per Mcf.  The Company's combined average realized sales price for the quarter was $30.75 per Boe, which represents a 30% decrease from $44.15 per Boe that was realized in the fourth quarter of 2018 and a decrease of 11% compared to $34.56 per Boe in the third quarter of 2019. 

CANADIAN E&PS

(Late Wednesday) Press Release - Athabasca provided its 2019 year-end results and annual reserves. Corporate highlights include annual production of ~36,200 boe/d (87% liquids) which included ~10,100 boe/d (54% liquids) in Light Oil and ~26,100 bbl/d in Thermal Oil. Annual Adjusted Funds Flow of ~$155 million ($0.30/share) and ~$140 million of capital expenditures resulting in approximately $15 million of Free Cash Flow. The company maintained top decile annual Light Oil Operating Netback of $25.68/boe; annual Thermal Oil Operating Netback of $19.59/bbl ($23.35/bbl Leismer & $11.50/bbl Hangingstone).

TD Securities downgraded Athabasca to 'Hold' from 'Buy'.

Press Release - Canadian Natural Resources announced 2019 fourth quarter and year end results. Net earnings of $5,416 million were realized in 2019, while adjusted net earnings of $3,795 million were achieved in 2019, a $532 million increase over 2018 levels. Cash flows from operating activities were $8,829 million in 2019, a decrease of $1,292 million compared to 2018 levels primarily due to the impact of changes in non-cash working capital. Canadian Natural generated record annual adjusted funds flow of $10,267 million in 2019, an increase of 13% or $1,179 million over 2018 levels. The increase over 2018 was primarily due to higher crude oil and NGL netbacks in the Company's Exploration and Production segment and higher volumes in the Company's thermal in situ and international areas. Cash flows used in investing activities were $7,255 million in 2019, an increase of $2,441 million compared to 2018 levels as a result of the Devon Canada asset acquisition completed in 2019, partially offset by lower capital expenditures in the year.

Press Release - Canadian Natural Resources announced its Board of Directors has declared a quarterly cash dividend on its common shares of C$0.425 (forty-two and one half cents) per common share. The dividend will be payable April 1, 2020 to shareholders of record at the close of business on March 20, 2020. 

Press Release - Crescent Point Energy announced its operating and financial results for the year ended December 31, 2019. For the year ended December 31, 2019, the Company's adjusted funds flow totaled $1.83 billion, or $3.34 per share diluted. In fourth quarter, adjusted funds flow totaled $418.4 million, or $0.78 per share diluted. For the year ended December 31, 2019, Crescent Point's capital expenditures on drilling and development, facilities and seismic totaled $1.25 billion, including $343.4 million spent during fourth quarter. Capital expenditures in 2019 were at the mid-point of the Company's annual guidance range. As at December 31, 2019, the Company's net debt was approximately $2.8 billion with unutilized credit capacity of approximately $2.2 billion. Subsequent to the quarter, Crescent Point closed its previously announced sale of certain gas infrastructure assets for $500 million, further reducing its net debt and enhancing its unutilized credit capacity to approximately $2.7 billion.

Press Release - Crescent Point Energy announced its Board of Directors has declared a quarterly cash dividend of CDN $0.01 per share to be paid on April 1, 2020 for shareholders of record on March 15, 2020.

Press Release - Crescent Point Energy announced the Toronto Stock Exchange  has accepted its notice to implement a normal course issuer bid to purchase, for cancellation, up to 36,884,438 common shares, or seven percent of the Company's public float, as at February 28, 2020. The NCIB is scheduled to commence on March 9, 2020 and is due to expire on March 8, 2021.

(Late Wednesday) Press Release - MEG Energy reported its full year 2019 operational and financial results. Highlights include free cash flow of $528 million driven by adjusted funds flow of $726 million ($2.41 per share) and disciplined capital spend of $198 million; Bitumen production volumes of 93,082 barrels per day (bbls/d) at a steam-oil-ratio (SOR) of 2.22; Net operating costs of $5.24 per barrel, supported by record low non-energy operating costs of $4.61 per barrel and strong power sales which had the impact of offsetting 74% of per barrel energy operating costs resulting in a net energy operating cost of $0.63 per barrel; Average AWB blend sales price net of transportation and storage costs at Edmonton of US$42.20 per barrel which was better than the posted 2019 AWB index price of US$42.08 per barrel, notwithstanding 43% Enbridge mainline apportionment, highlighting the value of MEG's North American marketing strategy; and General and administrative expense of $68 million which was $15 million, or 18%, lower than 2018.

Press Release - On February 27, 2020, Morguard Real Estate Investment Trust announced that it was in formal discussions with Obsidian Energy regarding a potential lease amendment for its Penn West Plaza tenancy. These discussions continue and the Trust will advise when discussions are concluded.

(Late Wednesday) Press Release - Obsidian Energy announced that, further to its press release on February 27, 2020, the company have reached an agreement with our syndicated credit facility lenders to extend the date by which certain conditions are required to be met from March 4, 2020 to March 13, 2020. Those conditions include: the maturity dates of the Company's outstanding senior notes due on March 16, 2020, May 29, 2020 and December 2, 2020, totaling US$27 million, have been extended to at least November 30, 2021; the net rent amount payable under the Company's office lease will not exceed an aggregate amount of $10 million per annum for the years 2020 through 2024 and $833,333 for the month of January 2025, when the lease expires; and the building landlord has agreed to indemnify the Company on all existing subleases.

(Late Wednesday) Press Release - Peyto Exploration & Development reported operating and financial results for the fourth quarter and 2019 fiscal year. The company generated $117 million in free cashflow in 2019 and continued to strengthen the balance sheet with $78 million in net debt reduction. The company reported annual earnings per share of $0.81. Annual capital investments were 64% of FFO Of the total of $323 million of FFO ($1.96/share), $206 million was invested in the drilling of 61 gross (53 net) wells. The new wells contributed 75 mmcf/d of natural gas and 4,700 bbl/d of NGLs (66% pentanes and condensate) by year end at a cost of $12,000/boe/d. While this cost for new production was up from $9,800/boe/d in the previous year, it built a more liquids-rich barrel that captured a 54% higher netback.

OILFIELD SERVICES

Press Release - Calfrac Well Services announced its financial and operating results for the three months and year ended December 31, 2019. In the fourth quarter of 2019, the Company generated revenue of $317.1 million, a decrease of 36 percent from the fourth quarter in 2018, resulting primarily from lower pricing and activity in Canada and the United States. The company reported adjusted EBITDA of $26.9 million versus $62.9 million in the fourth quarter of 2018 and reported a net loss attributable to shareholders of Calfrac of $49.4 million or $0.34 per share diluted, compared to a net loss of $3.5 million or $0.02 per share diluted in 2018. Subsequent to the quarter, Calfrac executed an exchange offer of US$120.0 million of new 10.875% second lien secured notes due March 15, 2026 to holders of its existing 8.50% senior unsecured notes due June 15, 2026. The exchange will result in reduced leverage of approximately $130.0 million and a reduction of $7.3 million in annual debt service costs.

Press Release - Halliburton announced the pricing terms of its previously-announced cash tender offers to purchase up to $1,500,000,000 aggregate principal amount of its senior notes as identified in the table below, as well as the anticipated early settlement date for the Tender Offers on March 5, 2020, as previously announced. The terms and conditions of the Tender Offers are described in the Offer to Purchase, dated February 19, 2020, and remain unchanged.

REFINERS

Press Release - Calumet Specialty Products Partners reported results for the fourth quarter and year ended December 31, 2019. For the fourth quarter 2019, the Partnership's $38.6 million Net loss, or $0.48 of net loss per unit, and Adjusted EBITDA of $53.8 million included a $3.9 million favorable net impact related to the non-cash lower of cost or market inventory adjustments and the liquidation of last-in, first-out inventory layers. Excluding the impact of LCM, LIFO and other non-cash and non-recurring items, Adjusted net loss, Adjusted net loss per unit, and Adjusted EBITDA (excluding LCM/LIFO) were $17.8 million, $0.23 per unit, and $49.9 million, respectively. For the full year 2019, the Partnership's $43.6 million Net loss, or $0.55 of net loss per unit, and Adjusted EBITDA of $304.6 million included a $41.8 million favorable net impact related to the non-cash lower of cost or market inventory adjustments and the liquidation of last-in, first-out inventory layers. Excluding the impact of LCM, LIFO and other non-cash and non-recurring items, Adjusted net loss, Adjusted net loss per unit, and Adjusted EBITDA (excluding LCM/LIFO) were $5.2 million, $0.07 per unit, and $262.8 million, respectively.

Reuters - Japan's Seven & i Holdings has decided to abandon its proposed $22 billion acquisition of Marathon Petroleum's Speedway gas stations in the United States, a person familiar with the matter told Reuters. Seven & I, which runs the 7-Eleven convenience store chain, had been in exclusive talks to buy the Speedway business for $22 billion. The Nikkei newspaper, which first reported the news, said the company decided to pull the plug on the deal over worries on price. It also cited growing concerns about a global economic slowdown from the coronavirus.

MLPS & PIPELINES

(Late Wednesday) Press Release - Pembina Pipeline announced that its Board of Directors declared a common share cash dividend for March 2020 of $0.21 per share to be paid, subject to applicable law, on April 15, 2020 to shareholders of record on March 25, 2020. This dividend is designated an "eligible dividend" for Canadian income tax purposes. For non-resident shareholders, Pembina's common share dividends should be considered "qualified dividends" and may be subject to Canadian withholding tax.

MARKET COMMENTARY 

Wall Street futures were trading in the red, as the U.S. reported a surge in coronavirus cases. European shares fell as profit warnings from several companies soured market sentiment. In Asia, Japan's Nikkei ended higher, boosted by the healthcare and industrial sectors. The dollar index fell amid expectations that the Federal Reserve will cut interest rates further, while gold edged up on safe-haven buying. Oil prices rose following reports of OPEC backing extra oil output cut. Initial jobless claims and durable goods data are expected later in the day.

NASDAQ ENERGY TEAM THOUGHT LEADERSHIP


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Peyto Posts 20th Straight Year of Profitability - EnerCom Inc.

Posted: 04 Mar 2020 04:17 PM PST

CALGARY, Alberta, March 04, 2020 (GLOBE NEWSWIRE) -- Peyto Exploration & Development Corp. ("Peyto" or the "Company") is pleased to report operating and financial results for the fourth quarter and 2019 fiscal year. A 66% operating margin1 and 27% profit margin2 was achieved in 2019, allowing Peyto to deliver a 4% return on capital employed ("ROCE") and an 8% return on equity ("ROE") in the year.

PROFITABILITY = SUSTAINABILITY

  • Free Cashflow – Generated $117 million in free cashflow in 2019 and continued to strengthen the balance sheet with $78 million in net debt reduction.
  • Long Life, Low Decline – The PDP Reserve life index ("RLI") increased 8% year-over-year to 9.4 years and the base production decline for 2020 is forecast in the independent reserve report at 23%.
  • Annual Earnings per share of $0.81 – 2019 was the 20th consecutive year of profits with annual earnings of $134 million or 27% of revenue. Over the past 21 years, Peyto has invested $6.2 billion of total capital, resulting in $6.3 billion in total Funds from Operations and $2.6 billion in cumulative earnings. The Company has never incurred a write down nor recorded an impairment of its assets.
  • Low Cash Costs of $0.95/Mcfe ($5.69/boe) – Cash costs of $0.87Mcfe, before royalties of $0.08/Mcfe, included operating costs of $0.34/Mcfe, transportation of $0.19/Mcfe, G&A of $0.04/Mcfe and interest expense of $0.30/Mcfe. Total 2019 cash costs continue to be the lowest in the industry and when combined with a realized price of $2.78/Mcfe ($16.65/boe), resulted in a cash netback of $1.83/Mcfe ($10.96/boe) or a 66% operating margin. 
  • Annual capital investments were 64% of FFO – Of the total of $323 million of FFO ($1.96/share), $206 million was invested in the drilling of 61 gross (53 net) wells. The new wells contributed 75 mmcf/d of natural gas and 4,700 bbl/d of NGLs (66% pentanes and condensate) by year end at a cost of $12,000/boe/d. While this cost for new production was up from $9,800/boe/d in the previous year, it built a more liquids-rich barrel that captured a 54% higher netback.
  • Liquids production up 13% Condensate and NGL production averaged 10,922 bbls/d up 13% in 2019 while natural gas production averaged 419 MMcf/d down 15% from 2018. For Q4 2019, natural gas and liquids production was 397 MMcf/d and 11,221 bbls/d. Fourth quarter liquid yields increased 26% year-over-year to 28 bbl/mmcf. Realized liquids prices were 3.7 times that of gas when gas is converted to oil on an energy equivalent basis of 6 mcf equals 1 bbl.
  • Lower Emissions – GHG Emissions Intensity was further reduced in 2019 due to Peyto's ongoing installation of zero emissions wellsite controllers and pumps, and by pre-connecting new wells to existing gathering systems to eliminate flaring. Since implementation of its comprehensive emissions reduction program in 2014, the Company has achieved a methane flaring and venting intensity reduction of 38% and an overall GHG emissions intensity reduction of 28%.
  • Minimal Future Liabilities – The forecast cost of all Peyto's future abandonment and reclamation liability (wells, sites, & facilities) is $55 million (NPV5), which represents 1.7% of the $3.3 billion of forecast future value of the total developed reserves3 (NPV5).

2019 in Review
The year 2019 marked Peyto's 21st year of successful operations with the advancement of several key plays across the Company's Deep Basin lands. Most of the drilling took place in Cardium "sweet-spots" that exhibited higher condensate yields, particularly in the Wildhay area, while at the same time the company completed and tied in its first Montney well. In addition, a prolific Falher channel was discovered in the Ansell area and the first few development wells were brought on production. Peyto also continued to evaluate its South Brazeau acreage and late in the year commenced construction of a 16 km pipeline to connect this area to the Company's Brazeau gas plant. The Company significantly increased its Deep Basin land position in the year with 130 net sections (equivalent to 3.6 townships of land) purchased at Crown auctions and through private acquisition. The 108 net sections of land purchased at auction was acquired at a record low price of $37/acre.

The Average AECO daily natural gas price in Alberta was up 17% from the previous year to $1.67/GJ, while the NYMEX price in the US fell 19% to $2.56/MMBTU. WTI oil price was also down year over year by 13% to $57/bbl. While this lower oil price translated into lower realized natural gas liquids prices, Peyto's blend of NGLs still sold for significantly more than gas which is why drilling was directed to increasing liquids production. This focus on increasing liquids production and reserves, with PDP liquid reserves up 23% and liquid production up 13%, came at a higher finding and development cost of $1.55/Mcfe ($9.29/boe). The Company plans to keep innovating with its Cardium well design to lower this cost in 2020 while continuing to enjoy the higher netback and value realized from increased liquids production.

1. Operating Margin is defined as funds from operations divided by revenue before royalties and marketing but including realized hedging gains/losses.
2. Profit Margin is defined as net earnings for the quarter divided by revenue before royalties and marketing but including realized hedging gains/losses.
3. Total Developed Reserves includes Proved Developed Producing+Probable Additional reserves and Proved Developed Non-Producing+Probable Additional reserves.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl).  Natural gas liquids and oil volumes in barrel of oil (bbl) are converted to thousand cubic feet equivalent (Mcfe) using a ratio of one (1) barrel of oil to six (6) thousand cubic feet.  This could be misleading, particularly if used in isolation as it is based on an energy equivalency conversion method primarily applied at the burner tip and does not represent a value equivalency at the wellhead.

  Three Months Ended Dec 31 % Twelve Months Ended Dec 31 %
  2019
2018 Change 2019
2018 Change
Operations                    
Production                    
Natural gas (mcf/d) 397,419   458,792   -13 % 419,281   493,921   -15 %
Oil & NGLs (bbl/d) 11,221   10,273   9 % 10,922   9,692   13 %
Thousand cubic feet equivalent (mcfe/d @ 1:6) 464,745   520,430   -11 % 484,810   552,070   -12 %
Barrels of oil equivalent (boe/d @ 6:1) 77,457   86,738   -11 % 80,802   92,012   -12 %
Production per million common shares (boe/d) 470   526   -11 % 490   558   -12 %
Product prices                    
Natural gas ($/mcf) 1.96   2.43   -19 % 2.04   2.54   -20 %
Oil & NGLs ($/bbl) 43.85   44.83   -2 % 44.61   56.98   -22 %
Operating expenses ($/mcfe) 0.34   0.33   3 % 0.34   0.31   10 %
Transportation ($/mcfe) 0.19   0.19   -   0.19   0.17   12 %
Field netback ($/mcfe) 2.11   2.39   -12 % 2.17   2.66   -18 %
General & administrative expenses ($/mcfe) 0.02   0.04   -50 % 0.04   0.05   -20 %
Interest expense ($/mcfe) 0.31   0.27   15 % 0.30   0.26   15 %
Financial ($000, except per share*)                    
Revenue and realized hedging gains (losses) 1 116,691   145,109   -20 % 489,822   658,906   -26 %
Royalties 5,303   5,801   -9 % 13,653   26,622   -49 %
Funds from operations 75,974   99,635   -24 % 323,131   473,740   -32 %
Funds from operations per share 0.46   0.61   -25 % 1.96   2.87   -32 %
Total dividends 9,892   29,677   -67 % 39,570   118,709   -67 %
Total dividends per share 0.06   0.18   -67 % 0.24   0.72   -67 %
Payout ratio 13   30   -57 % 12   25   -52 %
Earnings 3,492   21,458   -84 % 133,495   129,110   3 %
Earnings per diluted share 0.02   0.13   -85 % 0.81   0.78   4 %
Capital expenditures 73,351   112,215   -35 % 206,431   232,363   -11 %
Weighted average common shares outstanding 164,874,175   164,874,175   -   164,874,175   164,874,175   -  
As at December 31                    
Net debt           1,146,659   1,224,422   -6 %
Shareholders' equity           1,713,917   1,680,462   2 %
Total assets           3,597,180   3,688,852   -2 %
1excludes revenue from sale of third-party volumes            
  Three Months Ended Dec 31 Twelve Months Ended Dec 31
($000 except per share) 2019 2018 2019 2018
Cash flows from operating activities 74,943   102,559   316,936   486,478  
Change in non-cash working capital 1,031   (3,955 ) 3,904   (17,131 )
Change in provision for performance-based compensation -   (12,527 ) -   (9,165 )
Performance based compensation -   13,558   2,291   13,558  
Funds from operations 75,974   99,635   323,131   473,740  
Funds from operations per share 0.46   0.60   1.96   2.87  

(1) Funds from operations ("FFO") - Management uses FFO to analyze the operating performance of its energy assets.  In order to facilitate comparative analysis, FFO is defined throughout this report as earnings before performance-based compensation, non‑cash and non‑recurring expenses.  Management believes that FFO is an important parameter to measure the value of an asset when combined with reserve life.  FFO is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP.  Therefore, FFO, as defined by Peyto, may not be comparable to similar measures presented by other issuers, and investors are cautioned that FFO should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP.  FFO cannot be assured and future dividends may vary.

The Peyto Strategy

For the past 21 years, the Peyto strategy has focused on maximizing the returns on shareholders' capital by investing that capital into the profitable development of long life, low cost, and low risk natural gas resource plays. This strategy of maximizing returns does not end in the field with just the efficient execution of exploration and production operations but continues on to the head office where the management of corporate costs, including the cost of capital, must be controlled to ensure true returns are ultimately realized. Alignment of goals between what is good for the Company, its shareholders and its employees and what is good for the environment and all stakeholders is critical to ensuring that the greatest returns are achieved. Evidence of the success Peyto has had deploying this strategy, through the years, is illustrated in the following table.

($/Mcfe) 2009   2010   2011   2012   2013   2014   2015   2016   2017   2018   2019       21 Year
Wt. Avg.
Sales Price $6.75   $6.15   $5.47   $4.21   $4.43   $5.04   $3.83   $3.18   $3.39   $3.27   $2.78       $4.59  
All cash costs but royalties2 ($1.12 ) ($0.99 ) ($0.82 ) ($0.73 ) ($0.75 ) ($0.71 ) ($0.67 ) ($0.63 ) ($0.68 ) ($0.79 ) ($0.87 )     ($0.76 )
Capital costs1 ($2.26 ) ($2.10 ) ($2.12 ) ($2.22 ) ($2.35 ) ($2.25 ) ($1.64 ) ($1.44 ) ($1.36 ) ($1.18 ) ($1.55 )     ($1.77 )
Profits $3.37   $3.06   $2.53   $1.26   $1.33   $2.08   $1.52   $1.12   $1.35   $1.30   $0.35       $2.06  
  50%   50%   46%   30%   30%   41%   40%   35%   40%   40%   13%       45%  
Royalty Owners $0.63   $0.64   $0.53   $0.32   $0.31   $0.37   $0.14   $0.13   $0.15   $0.13   $0.08       $0.47  
Shareholders $2.74   $2.42   $2.00   $0.94   $1.02   $1.71   $1.38   $0.99   $1.19   $1.17   $0.27       $1.59  
Div./Dist. paid $4.03   $3.37   $1.24   $1.04   $1.01   $1.05   $1.11   $1.01   $0.97   $0.59   $0.22       $1.31  

1. Capital costs to develop new producing reserves is the PDP FD&A.
2. Cash costs not including royalties but including Operating costs, Transportation, G&A and Interest.
3. Profit above is defined as the Sales Price, less all cash costs but royalites, less the PDP FD&A.
Table may not add due to rounding.

The consistency and repeatability of Peyto's operational execution in the field, combined with strict cost control in all aspects of its business has resulted in 45% of the average sales price being retained in profit over the past 21 years. This healthy margin of profit (as shown above), which benefits both royalty owners and shareholders, has been preserved despite a greater than 60% decline in commodity prices from a decade ago. Out of that profit, royalty owners have received approximately 23%, while shareholders, whose capital has been at risk, have received the balance. This margin of profit is what has and will continue to help insulate Peyto and its stakeholders from future volatility in commodity prices.

Capital Expenditures

Peyto drilled 61 gross (53 net) horizontal wells in 2019 and completed 59 gross (52 net) wells for a capital investment of $151 million. The Company also invested $20.5 million in the wellsite equipment and pipeline connections to bring these wells on production. Drilling costs per well and on a per-meter basis continued to drop, due to ongoing efficiency gains like pad drilling, while completion costs on a per stage basis were also lower due to increasing stage count efficiencies. An average of 27 frac stages were pumped per well, up from 22 stages in 2018. The table below outlines the past ten years of average horizontal drilling and completion costs.

  2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Gross Hz Spuds 52 70 86 99 123 140 126 135 70 61
Measured Depth (m) 3,762 3,903 4,017 4,179 4,251 4,309 4,197 4,229 4,020 3,848
                     
Drilling ($MM/well) $2.76 $2.82 $2.79 $2.72 $2.66 $2.16 $1.82 $1.90 $1.71 $1.62
$ per meter $734 $723 $694 $651 $626 $501 $433 $450 $425 $420
                     
Completion ($MM/well) $1.36 $1.68 $1.67 $1.63 $1.70 $1.21 $0.86 $1.00 $1.13 $1.01*
Hz Length (m) 1,335 1,303 1,358 1,409 1,460 1,531 1,460 1,241 1,348 1,484
$ per Hz Length (m) $1,017 $1,286 $1,231 $1,153 $1,166 $792 $587 $803 $751 $679
$ '000 per Stage $231 $246 $257 $188 $168 $115 $79 $81 $51 $38

*Peyto's Montney well is excluded from drilling and completion cost comparison.

The $26.5 million invested in facilities and major pipeline projects included $13 million in new pipelines and liquid handling facilities at Wildhay to accommodate the growing Cardium liquids-rich production. New condensate stabilization and storage facilities increased Wildhay's condensate processing capacity from 1,400 bbl/d to 4,300 bbl/d and site storage from 2,000 bbl to 4,000 bbl. Other projects included the start of construction of the South Brazeau pipeline, Oldman North facility modifications, and pipeline looping projects in the Greater Sundance Area.

Peyto had a very successful year of acquiring new lands during 2019 which contributed to the increase in undeveloped drilling locations in the annual reserve evaluation from 1,201 to 1,280 gross locations (630 PU and 405 PA locations). In total, 130 net sections of new lands were acquired at Crown sales and through acquisition. Within the Greater Sundance Area, 58 net sections of new Cardium lands were acquired, helping drive the 18% increase in 2P Cardium inventory to 442 locations. Much of this new land was subsequently evaluated at year end with a 98 square km 3D seismic acquisition which will help to define additional Cardium and Spirit River drilling targets.

The following table summarizes the capital investments for the fourth quarter and 2019 fiscal year.


 
Three Months ended December 31 Twelve Months ended December 31
($000) 2019
2018
2019 2018
Land 186   106   2,716   3,291  
Seismic 1,600   2,000   4,588   5,216  
Drilling 36,325   57,383   86,053   115,610  
Completions 21,125   36,369   64,973   72,274  
Equipping & Tie-ins 9,317   10,716   20,505   20,766  
Facilities & Pipelines 4,798   3,691   26,540   17,293  
Acquisitions -   1,950   1,071   1,950  
Dispositions -   -   (15 ) (4,037 )
Total Capital Expenditures 73,351   112,215   206,431   232,363  

Reserves

Using 64% of Funds from Operations, Peyto was successful in effectively holding reserve volumes flat in all categories, however, the significant reduction in commodity price forecasts used by the independent engineering consultants resulted in a negative change in NPV per share. Volumes on a debt adjusted share basis were further impacted by the 46% drop in Peyto share price which was used in the debt adjustment calculation. The following table illustrates the change in reserve volumes and Net Present Value ("NPV") of future cash flows, discounted at 5%, before income tax and using Insite forecast pricing.

  As at December 31 % Change, % Change, per debt
  2019
2018
per share adjusted share
Reserves (BCFe)            
Proved Producing 1,600   1,644   (3%)  (30%)
Total Proved 3,164   3,098   2%   (26%)
Proved + Probable Additional 4,888   4,817   1%   (27%)
             
Net Present Value ($millions) Discounted at 5%            
Proved Producing $2,622   $3,180    (18%) (25%)
Total Proved $4,514   $5,029   (10%) (11%)
Proved + Probable Additional $6,818   $7,345   (7%) (7%)

†Per share reserves are adjusted for changes in net debt by converting debt to equity using the Dec 31 share price of $7.08 for 2018 and share price of $3.80 for 2019. Net Present Values are adjusted for debt by subtracting net debt from the value prior to calculating per share amounts.
Note: based on the InSite Petroleum Consultants ("InSite") report effective December 31, 2019.  The InSite price forecast is available at www.InSitepc.com. The complete statement of reserves data and required reporting in compliance with NI 51-101 will be included in Peyto's Annual Information Form to be released in March 2020.

For more information on Peyto's reserves, refer to the Press Release dated February 19, 2020 announcing the Year End Reserve Report which is available on the website at www.peyto.com. 

Fourth Quarter 2019

Peyto ramped up capital investments during the fourth quarter to double that of the previous quarter in order to bring on additional new production into the winter heating season. During the quarter, between four and five drilling rigs were active across the Greater Sundance Area, split between Cardium and Spirit River formations, as illustrated in the table below. Total capital of $57 million was invested in the drilling of 25 gross (22 net) wells and the completion of 26 gross (22 net) wells. In addition, $9 million was invested in wellsite equipment and tie-ins while $5 million was invested in facility upgrades and major pipeline infrastructure. New seismic accounted for $2 million in the quarter, while 5 sections of land were acquired at Crown sales.

  Field Total
Wells
Drilled
Zone Sundance Nosehill Wildhay Ansell/
Minehead
Whitehorse Kisku/
Kakwa
Brazeau
Belly River                
Cardium 4   11         15
Notikewin       1     2 3
Falher       2       2
Wilrich 3     1       4
Bluesky   1           1
Montney                
Total 7 1 11 4     2 25

Production during the fourth quarter of 2019 grew from 75,000 boe/d in October to exit the year at a peak of 82,000 boe/d, averaging 77,457 boe/d, or 397 mmcf/d of gas and 11,221 bbl/d of NGLs (14.5% liquid). This average Q4 production was down 11% from Q4 2018 which averaged 86,738 boe/d (459 mmcf/d and 10,273 bbl/d of NGLs or 12% liquid) due to 35% lower capital investments. The production additions in the fourth quarter 2019 were dominated (60%) by Cardium wells which drove the increase in relative liquids production. Of the 11,221 bbls/d of NGL production, approximately 60% or 6,650 bbl/d was condensate and C5+, while the remaining volume was effectively split between propane and butane. Peyto operated its Oldman deep cut plant during the quarter as propane and butane prices, relative to gas prices, justified the extra cost to strip those products out into liquid form.

The Company's realized price for natural gas in Q4 2019 was $3.12/Mcf, prior to $0.92 market diversification activities and a $0.24/Mcf hedging loss, while its realized liquids price was $43.85/bbl, including a $0.73/bbl hedging gain, which yielded a combined revenue stream of $2.76/Mcfe. This net sales price was 9% lower than the $3.03/Mcfe realized in Q4 2018. Total cash costs in Q4 2019 were $0.98/Mcfe ($5.88/boe) up from $0.95/Mcfe in Q4 2018 due to slightly higher per unit interest charges and operating costs as a result of reduced production volumes. The total Q4 2019 cash cost included royalties of $0.12/Mcfe, operating costs of $0.34/Mcfe, transportation of $0.19/Mcfe, G&A of $0.02/Mcfe and interest of $0.31/Mcfe.  Peyto generated total funds from operations of $76 million in the quarter, or $1.78/Mcfe, equating to a 65% operating margin. DD&A charges of $1.38/Mcfe, as well as a provision for current and future performance-based compensation and income tax, reduced FFO to earnings of $0.09/Mcfe, or a 3% profit margin. No impairments were recorded in the quarter and dividends to shareholders totaled $0.23/Mcfe.

Marketing

Peyto actively markets all components of its production stream including natural gas, condensate, pentane, butane and propane. Natural gas was sold in 2019 at various hubs including AECO, Dawn, Ventura, Emerson 2 and Henry Hub using both physical fixed price and basis transactions to access those locations (diversification activities). Natural gas prices were left to float on daily pricing or locked in using fixed price swaps at those hubs and Peyto's realized price is benchmarked against those local prices, then adjusted for transportation (either physical or synthetic) to those markets. The Company's liquids are also actively marketed with condensate being sold on a monthly index differential linked to West Texas Intermediate ("WTI") oil prices. Peyto's NGLs (a blend of pentanes plus, butane and propane) are fractionated by a third party in Fort Saskatchewan, Alberta and Peyto markets each product separately. Pentanes Plus are sold on a monthly index differential linked to WTI, with some volumes forward sold on fixed differentials to WTI. Butane is sold as a percent of WTI or a fixed differential to Mount Belvieu, Texas markets. Propane is sold on a fixed differential to Conway, Kansas markets. While some products require annual term contracts to ensure delivery paths remain open, others can be marketed on the daily spot market.

During 2019 Peyto sold 77% of its natural gas at AECO, 5% at Dawn, 3% at Emerson, 4% at Ventura, and 11% at Henry Hub. Net of diversification activities, Peyto realized a before hedge price of $1.91/mcf. Hedging activity improved this price by $0.13/mcf, to $2.04/mcf.

Condensate and Pentane Plus volumes were sold for an average price of $69.22/bbl in 2019, down from $75.46 in 2018, and as compared to Canadian WTI oil price that averaged $75.68/bbl. The $6.46/bbl differential from light oil price was down from $8.43/bbl in the previous year. Butane and propane volumes were sold in combination at an average price of $10.43/bbl, far below their typical price between 25-50% of light oil price, due to a significant surplus of supplies overwhelming the local Alberta market. Much of this surplus has subsequently been cleared and spot pricing has improved. Peyto will begin to realize these improved prices as the April 2019 to March 2020 term contract year ends. Peyto's realized price by product and relative to benchmark prices is shown in the following table.

Realized Commodity Prices by Component

  Three Months ended December 31 Twelve Months ended December 31
  2019   2018 2019   2018
Natural gas ($/mcf) 3.12   2.18   2.63   1.70  
Diversification activities ($/mcf) (0.92 ) (0.09 ) (0.72 ) (0.02 )
Gas hedging ($/mcf) (0.24 ) 0.34   0.13   0.86  
Realized total natural gas ($/mcf) 1.96   2.43   2.04   2.54  
Oil, condensate and C5+ ($/bbl) 65.13   54.86   65.76   74.49  
Oil hedging ($/bbl) 1.26   4.54   3.46   0.97  
Realized oil, condy and C5+ ($/bbl) 66.39   59.40   69.22   75.46  
Realized butane and propane ($/bbl) 12.45   31.43   10.43   31.43  

liquids prices are Peyto realized prices in Canadian dollars adjusted for fractionation, transportation and market differentials.
Peyto natural gas has an average heating value of approximately 1.15 GJ/mcf

Benchmark Commodity Prices

  Three Months ended December 31 Twelve Months ended December 31
  2019
2018 2019
  2018
AECO 7A monthly ($/GJ) 2.21   1.80   1.54   1.45  
AECO 5A daily ($/GJ) 2.35   1.48   1.67   1.42  
Empress daily ($GJ) 2.59   4.06   2.43   2.93  
NYMEX (US$/MMbtu) 2.41   3.74   2.53   3.07  
Ventura daily (US$/MMbtu) 2.64   4.18   2.47   3.06  
Dawn daily (US$/MMbtu) 2.42   3.91   2.44   3.10  
Conway Propane (US$/bbl) 19.73   28.96   19.91   30.31  
Canadian WTI ($/bbl) 75.18   77.54   75.68   83.89  

2019 average CND/USD exchange rate of 1.3269.

Details of Peyto's ongoing marketing and diversification efforts are available on Peyto's website at
http://www.peyto.com/Files/Operations/Marketing/hedges.pdf.

Activity Update

Peyto began 2020 with 5 drilling rigs running and has spud 12 gross (10 net) wells, completed 15 gross (13 net) wells and connected 9 gross (8 net) wells to the end of February. There are 5 gross (4 net) additional wells which came onstream at the beginning of March. The Q1 2020 drilling program has been focused on both Cardium and Spirit River formations that exhibit high liquid yields. Operations were delayed by the extreme cold weather experienced in mid-January as scheduled frac service was disrupted. This disruption delayed the timing of new well production additions. Cardium well results in this first quarter continue to provide impressive initial liquid yields of over 100 bbls/mmcf of high value condensate and pentanes.

During the first 2 months of 2020, Peyto also finished construction of a strategic 16 km, 8-inch pipeline in South Brazeau linking the Chambers area to Peyto's existing Brazeau gas gathering system. This pipeline re-directed existing volumes that were flowing to a third-party plant to the Peyto operated Brazeau plant and will support the future development of a large inventory of liquids-rich Spirit River and Cardium locations in the Chambers area. The Company currently has one drilling rig operating in this area.

In January, the Company completed a 98 square km 3D seismic shoot in the Ansell area over a large portion of lands that were purchased in 2019. This proprietary data will be used in the identification of Cardium and Spirit River targets later this year.

The recent COVID-19 virus outbreak and resultant reduced energy demand outlook combined with a lack of winter heating demand in North American has weakened both oil and natural gas prices significantly since Peyto announced its capital budget in December. As a result, the Company has deferred approximately $26 million of the Q1 drilling program to later in the year when commodity prices are expected to recover.  The remaining 2 drilling rigs currently operating for Peyto are focused on high quality Cardium targets and Peyto intends to continue to drill through breakup before ramping up activity in the second half of the year.

Business Development and New Ventures

While the current financial difficulties of the natural gas sector have brought challenges, they have also brought forward tremendous opportunities. New technologies and resource plays have been proven over the past decade and stand ready for development as producer behaviour and the marketplace restore economic order. Peyto views the next couple of years as a clear window to capitalize on these opportunities through a number of strategies and has created a new internal team to pursue these opportunities. This team will focus on a spectrum of ideas ranging from the establishment of new core areas, either organically or through acquisition, a strengthening of Peyto's existing core areas through large scale multi-company joint venture aggregation, expansion of direct product sales markets such as additional power generation, and other ideas and projects across the hydrocarbon value chain. Peyto has a well-seasoned operations team capable of taking its time-proven, low capital and operating cost results, to other geographical areas and other play types.

Environment, Social and Governance ("ESG")

Peyto improved its ESG standing in 2019 with strong environmental performance, increased social factors and improved corporate governance. On the environmental front, Peyto continued to reduce its GHG emissions intensity while capturing more methane emissions across its operations. The ongoing installation of low bleed controllers and zero emissions pumps at well sites continued throughout the year with 304 controllers and 62 pumps installed in 2019, bringing the total to 448 controllers and 233 pumps installed over the past 5 years. Peyto is also testing the design of a new, zero emissions controller which it expects to start installing this year. In addition, almost all new wells drilled in the year were pre-connected to existing gas gathering systems which eliminated the need to flare gas during completion cleanup flows which further reduced GHG emissions. Since implementation of its comprehensive emissions reduction program in 2014, the Company has achieved an overall GHG emissions intensity reduction of 28% and methane flaring and venting intensity reduction of 38% and is well on its way to the stated goal of 50% reduction. The Company also continued its industry leading practice of using less water per BOE of reserves developed with an active water management program and efficient completion design.

From a social perspective, the health and welfare of Peyto's employees and contractors remained the highest priority for the company. A strong core training program and progression plan for operations personnel is at the heart of the Company's safety culture and provides a solid foundation of organizational competence. This safety culture is further strengthened and propagated throughout the organization through a multi-faceted, active and ongoing plan that involves regular audits, educational sessions, emergency practice drills and information dissemination to all personnel working within the organization. Two primary focuses, personnel safety and equipment maintenance, protect not only Peyto's employees and contractors but also the public at large and natural surroundings. In addition, the Company closely monitors any injury accidents and near misses within a culture of continuous improvement in an effort to implement initiatives to increase the safety of all workers. For 2019, total recordable injury frequency (TRIF) and lost time injury frequency (LTIF), including employees, consultants, field operators, and all third-party service company personnel, was 0.68 and 0, respectively. This is down from the previous year at 0.94 and 0.13. For Peyto employees, consultants and field operators only, the TRIF and LTIF was zero in 2019.

From a corporate governance perspective, Peyto increased its board independence with the addition of Mr. John Rossall to Peyto's board, as well as the adoption and strengthening of board mandates, corporate by-laws and policies. New policy adoption included say-on-pay, share ownership guidelines, compensation clawback, board renewal, enhanced diversity and shareholder engagement. In addition, Peyto further enhanced disclosure surrounding CEO compensation, anti-hedging policy, nomination process, director qualifications and annual general meeting materials.

Please refer to Peyto's 2019 Sustainability Report and policies under Corporate Responsibility at www.peyto.com.

2020 Outlook

As this new decade begins, Peyto is preparing to embark on a new chapter for the company. Once a tiny junior, the company has grown over the past two decades into a leading Canadian producer, well known for its efficiency, profitability and sustainability. With strong foundational support from its existing resource base, extensive infrastructure assets and strong technical skillset, Peyto is well positioned to capitalize on future opportunities.

The Company's current three-year plan remains intact with a focus on maximizing returns, strengthening its balance sheet and focusing on its core competencies. As production declines continue to shallow and producing reserve life grows, Peyto's base cashflows will continue to strengthen requiring less future capital to offset declines. With the current commodity price outlook driving reduced activity, the domestic natural gas market looks to become less supply driven and more demand driven which should be constructive for natural gas prices and ultimately reward Canadian natural gas producers. Capital guidance for the year remains between $250 and $300 million. As always, Peyto will remain nimble to the volatile market conditions while staying focused on maximizing full cycle returns.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2019 fourth quarter and full year financial results on Thursday, March 5th, 2020, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-844-492-6041 (North America) or 1-478-219-0837 (International). Shareholders and interested investors are encouraged to ask questions about Peyto and its most recent results. Questions can be submitted prior to the call at [email protected]. The conference call can also be accessed through the internet https://edge.media-server.com/mmc/p/bpckqhxv. The conference call will be archived on the Peyto Exploration & Development website at www.peyto.com.

Annual General Meeting

Peyto's Annual General Meeting of Shareholders is scheduled for 3:00 p.m. on Thursday, May 7, 2020 at the Eau Claire Tower, +15 level, 600 – 3rd Avenue SW, Calgary, Alberta. Shareholders are encouraged to visit the Peyto website at www.peyto.com where there is a wealth of information designed to inform and educate investors. A monthly President's Report can also be found on the website which follows the progress of the capital program and the ensuing production growth, along with video and audio commentary from Peyto's senior management.

Management's Discussion and Analysis

A copy of the fourth quarter report to shareholders, including the MD&A, unaudited financial statements and related notes, is available at http://www.peyto.com/Files/Financials/2019/Q42019FS.pdf and at http://www.peyto.com/Files/Financials/2019/Q42019MDA.pdf and will be filed at SEDAR, www.sedar.com at a later date.

Darren Gee
President and CEO
Phone: (403) 261-6081
Fax:     (403) 451-4100

Certain information set forth in this document and Management's Discussion and Analysis, including management's assessment of Peyto's future plans and operations, capital expenditures and capital efficiencies, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond these parties' control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources.  Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Peyto's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Peyto will derive there from. In addition, Peyto is providing future oriented financial information set out in this press release for the purposes of providing clarity with respect to Peyto's strategic direction and readers are cautioned that this information may not be appropriate for any other purpose. Other than is required pursuant to applicable securities law, Peyto does not undertake to update forward looking statements at any particular time. To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (BOE). Peyto uses the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 BOE ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on current prices. While the BOE ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

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Frontera Delivers Strong Fourth Quarter and 2019 Financial and Operational Results - Benzinga

Posted: 05 Mar 2020 01:30 PM PST

Meets or Exceeds all 2019 Guidance Metrics and Delivers Cash Provided by Operating Activities in Excess of Cash Used in Investing Activities

$123 million of Cash Returned to Shareholders Via Share Buybacks and Dividends in 2019

TORONTO, March 5, 2020 /CNW/ - Frontera Energy Corporation (TSX:FEC) ("Frontera" or the "Company") announced today the release of its Consolidated Financial Statements, 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") for the year ended December 31, 2019. These documents, among others, will be posted on the Company's website at www.fronteraenergy.ca 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.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

Operational

  • Production remained stable averaging 70,905 boe/d in the fourth quarter of 2019 and 70,875 boe/d for the full year of 2019.
  • As previously reported, 102% of gross 2P reserves and 112% of net 2P reserves were replaced in 2019 with 11% growth in Colombia gross PDP reserves, and gross 2P reserve life index for Colombia of over 7 years.
  • Second testing period on the La Belleza exploration on the VIM-1 block yielded very encouraging results with stable production rates and lowering water cut. The Asai-1 exploration well on the Guama block is drilling at 7,400 feet towards a target depth of 12,500 feet on time and on budget.
  • Oil production represented 97% of total Company production in the fourth quarter of 2019, compared to 97% in the third quarter of 2019 and 95% in the fourth quarter of 2018.

Financial

  • Net income was $69 million ($0.71/share) in the fourth quarter of 2019 compared to a net loss of $49 million ($0.50/share) in the third quarter of 2019 and a net loss of $117 million ($1.17/share) in the fourth quarter of 2018.
  • Cash provided by operating activities of $152 million in the fourth quarter of 2019 was 22% higher than the prior quarter and over 100% higher than in the prior year quarter. During 2019, the Company delivered $131 million of excess cash provided by operating activities of $547 million, compared to cash used in investing activities of $416 million.
  • Operating EBITDA of $137 million was 10% higher than the prior quarter and 25% higher than the prior year quarter.
  • Capital expenditures of $132 million in the fourth quarter of 2019 were 87% higher than in the third quarter of 2019 and 15% lower than the fourth quarter of 2018, as anticipated, reflecting an increase in exploration activity during the quarter on the VIM-1 and CPE-6 blocks and the expansion of water treatment and disposal capacity at CPE-6.
  • Total cash, including restricted cash, was $456 million as at December 31, 2019, up 3% from the third quarter of 2019 and down 23% compared to December 31, 2018, reflecting $123 million in cash returned to shareholders in 2019 via dividends and buybacks.
  • Approximately 40% of expected 2020 net production after royalties was hedged, as of year-end, using a variety of financial instruments with an average Brent floor price of $58.44/bbl.
  • General and administrative expenses ("G&A") of $76 million in 2019 was down 18% compared to 2018, ahead of management's expectations of 10% to 15% savings during the year.

Shareholder Initiatives

  • During the fourth quarter of 2019, the Company repurchased for cancellation 1.5 million shares at a cost of $12 million (C$10.06/share) under its normal course issuer bid ("NCIB"). Since October 18, 2019 to date, under the renewed NCIB, the Company has repurchased for cancellation 2.9 million shares at a cost of $22 million (C$9.79/share).
  • On March 4, 2020, the Company's Board of Directors declared a dividend, payable on or about April 16, 2020 of C$0.205 (approximately $15 million in aggregate), to common shareholders of record on April 2, 2020.

2019 and 2020 Guidance

The Company delivered 2019 results better than its upwardly revised guidance for Operating EBITDA and average daily production and at the bottom end of its guidance for production and transportation costs. EBITDA sensitivities for all the major inputs for 2020 Guidance can be found on page 7 of the Company's corporate presentation available on its website.








2019 Results

2019 Guidance (1)

2020 Guidance

Operating EBITDA

($MM)

586

525 to 575

400 to 450

Capital Expenditures

($MM)

346

325 to 375

325 to 375

Average Daily Production

(boe/d)

70,875

65,000 to 70,000

60,000 to 65,000

Production Costs (2)

($/boe)

11.99

12.00 to 12.50

$11.50 to $12.50

Transportation Costs (3)

($/boe)

12.51

12.50 to 13.50

$12.50 to $13.50

Brent Oil Price Assumption (4)

($/bbl)

64.16

65.00

60.00

Oil Price Differential (4)

($/bbl)

2.74

3.50

4.00

Foreign Exchange Rate (4)

(USD:COP)

3,283:1

3,100:1

3,300:1

1Revised 2019 Guidance, as updated on August 1, 2019, with more positive metrics than original guidance

2Calculated using production before royalties as this most accurately reflects per unit production costs

3Calculated using production after royalties as this most accurately reflects per unit transportation costs

42019 averages from Bloomberg

 

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

"The strong operational and financial results delivered by the Frontera team in 2019 enabled the Company to continue delivering significant returns to shareholders through dividends and buybacks while maintaining a strong balance sheet and a significant net cash position. Since announcing a dividend policy in December 2018, the Company has paid out C$1.645/share in dividends, a yield of over 13%. Additionally, since announcing our first share buyback program in July 2018, Frontera has bought back over 5.6 million shares or nearly 6% of the issued equity. Frontera is off to a positive start in 2020, with exploration success in Colombia and many additional opportunities to continue growing the business in 2020 and coming years."

Richard Herbert, Chief Executive Officer of Frontera, commented:

"2019 was the year when Frontera repositioned its portfolio for growth, while maintaining stable production and growing reserves in its core assets. We added new exploration blocks in Colombia, Ecuador and offshore Guyana, while also executing a farm-in agreement with Parex Resources on the VIM-1 block in Colombia which has already delivered exploration success. During 2019 we increased production from the CPE-6 block by more than three times, while adding reserves on the block through successful near field exploration. Quifa production was also strong in 2019 following the expansion of water treatment and disposal capacity at the end of 2018. Overall our strategy is working, as we maintain our core areas of operation in Colombia and deliver new opportunities through exploration. Our teams executed on the implementation of cost savings initiatives, with G&A down 18% year over year, production costs down 4% on a boe basis, and transportation costs down 2% on a boe basis. These projects combined with solid production, enabled the Company to deliver cash provided by operating activities which was $131 million higher than cash used in investing activities.

In 2020 we will drill meaningful exploration wells in Colombia, Ecuador and offshore Guyana. We will continue to manage our capital exposure and our risk when it comes to exploration. Our new asset teams are looking to start delivering more cost savings and efficiency improvements throughout the portfolio as they move through 2020.

Finally, although the price of oil is off to a challenging start in 2020, Frontera is disciplined and we will manage our capital program and cost structure to weather weaker commodity prices. For 2020, the Company has hedged approximately 40% of net production at Brent oil prices above $58/bbl, and we are committed to maintaining a strong balance sheet through this period. We have also acted swiftly to the recent downward movement in oil prices. In addition to cutting all non essential travel and reducing contractor headcount, we have evaluated all our 2020 capital projects and have identified between $50 million to $75 million in capital projects that can be deferred depending on the price of oil."

Financial Results








2019


2018



Q4

Q3

Full Year


Q4

Full Year

Revenue

($MM)

351

278

1,384


265

1,320

Net income (loss) (1)

($MM)

69

(49)

294


(117)

(259)

Per share - basic (2)

($)

0.71

(0.50)

3.01


(1.17)

(2.59)

Net sales (3)

($MM)

340

266

1,262


228

1,083

Cash provided by operating activities

($MM)

152

124

547


4

347

Operating EBITDA (3)

($MM)

137

125

586


109

413

Operating EBITDA margin (Operating EBITDA/Net sales)(3)

(%)

40%

47%

46%


48%

38%

General and administrative (G&A)

($MM)

23

18

76


22

93

Capital expenditures

($MM)

132

71

346


156

446

Total cash, including restricted cash(4)

($MM)

456

442

456


588

588

Working capital

($MM)

71

125

71


216

216

Shares outstanding - basic(5)

(MM)

96

98

96


98

98

1Net income (loss) attributable to equity holders of the Company

2Basic and diluted weighted average numbers of common shares for the year ended December 31, 2019 were 97,871,378 and 99,532,362 (December 31, 2018: 99,841,652)

3These metrics are Non-IFRS financial measures. See Advisories - "Non-IFRS Financial Measures" - below and "Non-IFRS Measures" on page 18 of the MD&A

4Includes $328 million of cash and cash equivalents, $37 million of short term restricted cash and $90 million of long term restricted cash as at December 31, 2019 (includes $314 million of cash and cash equivalents, $36 million of short term restricted cash, and $92 million of long term restricted cash as at September 30, 2019, and $446 million of cash and cash equivalents, $40 million of short term restricted cash, and $103 million of long term restricted cash as at December 31, 2018)

5Basic shares outstanding are as at the date of the reporting period

 

The average Brent oil benchmark price increased in the fourth quarter of 2019 to an average of $62.42/bbl, up 1% from $62.03/bbl in the third quarter of 2019. Brent oil benchmark price averaged $68.60/bbl in the fourth quarter of 2018. The Company's net realized sales price of $56.22/bbl in the fourth quarter of 2019 was 6% higher than the prior quarter and 14% higher than in the fourth quarter of 2018.

In 2019, net income attributable to equity holders of the Company was $294 million ($3.01/share), compared to a net loss of $259 million in 2018. During the fourth quarter of 2019, net income attributable to equity holders of the Company was $69 million ($0.71/share), compared with net losses in each of the prior quarter and prior year quarter. In addition to operational execution net income growth was driven by the booking of additional deferred tax assets resulting from the growth in the Company's reserves during 2019 and a reduction in presumptive tax rates in Colombia.

For the fourth quarter of 2019, net sales of $340 million were 28% higher in the third quarter of 2019 and 49% higher than in the fourth quarter of 2018 driven by higher net sales realized price of $56.22/boe and additional sales volumes in Peru during the quarter.

Cash provided by operating activities was $547 million in 2019, 58% higher than in 2018 reflecting higher net realized sales price, stable production, higher sales volumes and lower costs. In the fourth quarter of 2019 cash provided by operating activities was $152 million in the fourth quarter compared to cash provided by operating activities of $124 million in the third quarter of 2019, reflecting higher sales volumes and oil prices. During the fourth quarter of 2019 the Company generated cash provided by operating activities that was $19 million higher than capital expenditures of $132 million.

Operating EBITDA of $137 million in the fourth quarter of 2019 increased 10% in comparison with the third quarter of 2019 and was 25% higher than in the fourth quarter of 2018 as a result of a reduction of inventory in Peru and stronger realized prices.

For 2019, production costs were 4% lower than in 2018 on a boe basis as a result of a weaker peso and cost savings initiatives implemented in the second half of the year. Production costs during the fourth quarter of 2019 of $13.76/boe were 19% higher compared to the third quarter of 2019 and 8% higher than in the fourth quarter of 2018 reflecting a higher amount of work over and well service activity in Colombia and costs associated with increased sales from Peru.

On a boe basis, transportation costs were 2% lower in 2019 compared to 2018. In the fourth quarter of 2019 transportation costs were $12.84/boe, 7% higher than in the third quarter of 2019 and flat compared to the fourth quarter of 2018.

G&A costs were 18% lower in 2019 compared to 2018 as a result of ongoing cost savings initiatives, lower employee-related costs and lower office lease costs due to the adoption of IFRS 16. G&A costs were $23 million during the fourth quarter of 2019, 24% higher than the third quarter of 2019 and 5% higher than the fourth quarter of 2018, primarily as a result of a short-term employee incentive plan implemented in the fourth quarter of 2019.

Cash and cash equivalents including restricted cash totaled $456 million as at December 31, 2019, an increase of $14 million compared to September 30, 2019 reflecting $67 million of cash provided by operating activities in excess of cash used in investing activities offset by $15 million in dividends paid, $12 million used to repurchase common shares and $17 million used in the payment of interest on long term debt.

During the fourth quarter of 2019 the Company paid a regular dividend of C$0.205/share. In addition, the Company paid its regular quarterly dividend of C$0.205/share on January 17, 2020 and on March 4, 2020, announced a regular quarterly dividend of C$0.205 to be paid on or about April 16, 2020 to shareholders of record on April 2, 2020.

In October 2019 the Company announced the renewal of its normal course issuer bid, pursuant to which the Company may repurchase up to 6,532,400 shares of the Company, representing 10% of the public float, during a 12 month period between October 18, 2019 and October 17, 2020. To date, under the renewed NCIB, the Company repurchased for cancellation 2,941,128 shares at an average price of C$9.79, at a cost of $22 million.

The Company has hedged approximately 40% of net production during the first three quarters of 2020, and about 15% of net production for the fourth quarter of 2020 using a combination of Brent oil price linked purchased put options, zero cost collars, put spreads and three-way collars to protect the Company's balance sheet and capital program within hedging limits set by the Board of Directors.

Operational Results



Production, before royalties(1)

2019

2018


Q4

Q3

Q2

Q1

Full Year

Q4

Full Year

Oil and liquids (bbl/d)








Colombia

58,517

61,420

61,956

63,052

61,224

59,687

58,675

Peru

10,164

6,510

9,975

2,271

7,250

8,974

8,171

Total oil and liquids (bbl/d)

68,681

67,930

71,931

65,323

68,474

68,661

66,846









Natural gas (boe/d)(2)








Colombia

2,224

2,283

2,454

2,651

2,401

3,263

4,186

Total natural gas (boe/d)

2,224

2,283

2,454

2,651

2,401

3,263

4,186









Total equivalent production (boe/d)

70,905

70,213

74,385

67,974

70,875

71,924

71,032

1Additional production details are available in the MD&A "Financial and Operational Results" section, page 6.

2Colombian standard natural gas conversion ratio of 5.7 Mcf per bbl as required by the Colombian Ministry of Mines and Energy.

 

Production in the fourth quarter of 2019 averaged 70,905 boe/d, in-line with 70,213 boe/d in the third quarter of 2019 as a result of stable production levels in Peru during the quarter and natural declines and temporary production shut-ins in Colombia as water handling capacity was added in the CPE-6 block.

Company production was 97% oil-weighted in the fourth quarter of 2019 compared to 97% in the third quarter of 2019 and 95% in the fourth quarter of 2018. The higher oil mix as a percentage of total production results in better realized prices given stronger Brent oil prices and narrow price differentials during the fourth quarter of 2019.

During the fourth quarter of 2019, capital expenditures were $132 million up 87% compared to $71 million in the previous quarter and down 15% from the fourth quarter of 2018. The increase reflects additional planned exploration drilling in the fourth quarter of 2019 on the VIM-1 block in the Lower Magdalena Valley and on the CPE-6 block in the Llanos basin, combined with a water handling and disposal expansion project on the CPE-6 block. Additionally, the Company incurred costs associated with the 3D seismic acquisition on the Corentyne block offshore Guyana.

The Company drilled 21 wells during the fourth quarter of 2019, including 18 development wells and three exploration wells. Three previously disclosed exploration wells on the Sabanero block were subsequently reclassified as development wells of which two were drilled during the fourth quarter of 2019. During the first quarter of 2020, Frontera expects to drill 28 development wells (21 at Quifa, six at CPE-6, and one at Canaguaro), and commence drilling one exploration well (Asai-1 on the Guama block), targeting liquids and natural gas.

In December 2019, the Company began drilling the Canaguay-3 development well on Canaguaro block. On February 20, 2020, the well reached target depth with a measured depth of 15,193 feet, encountering a combined 55 feet of net oil pay over three separate Mirador formations. The well will be tested and is expected to be put on production in the coming weeks using existing infrastructure on the Canaguaro block.

On February 6, 2020, the Company (50% WI), along with its joint venture partner, Parex Resources Inc. (50% WI, operator), announced the results of the successful La Belleza-1 exploration well on the VIM-1 block in the Lower Magdalena Valley. The second well test yielded similar results as the first test with average production of 4,800 boe/d (2,670 bbl/d of 43 degree API oil, and 12.6 mmcf/d of natural gas), with a 14% draw down, well head flowing pressure of 3,770 psi and a lower water cut of 6%. The well remains shut-in for a pressure build up test which will help determine next steps. More drilling is expected on the block during 2020 as part of the ongoing evaluation and planning phase for commercial development.

In February 2020, the Company spud the Asai-1 exploration well on the Guama block in the Lower Magdalena Valley (Frontera 100% WI, operator), targeting a primary objective oil, natural gas condensate and natural gas structure in the Porquero formation at approximately 12,000 feet. The well is currently drilling at over 7,400 feet and has encountered natural gas shows in shallow, secondary objectives as expected. The well is expected to complete drilling in the middle of April 2020 with results in May 2020.

Fourth Quarter and Year End 2019 Conference Call Details

As previously disclosed, a conference call for investors and analysts will be held on Friday, March 6, 2020 at 8:00 a.m. (MST) and 10:00 a.m. (EST/GMT-5). Participants will include Gabriel de Alba, Chairman of the Board of Directors, Richard Herbert, Chief Executive Officer, David Dyck, Chief Financial Officer and select members of the senior management team.

Analysts and 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:

7833979

Webcast Audio:

www.fronteraenergy.ca



A replay of the conference call will be available until 11:59 p.m. (EST/GMT-5) Friday, March 20, 2020



Encore Toll Free Dial-in Number:

1-855-859-2056

Local Dial-in Number:

(416)-849-0833

Encore ID:

7833979

 

About Frontera:

Frontera Energy Corporation is a Canadian public company and a leading explorer and producer of crude oil and natural gas, with operations focused in South America. The Company has a diversified portfolio of assets with interests in more than 40 exploration and production blocks in Colombia, Peru, Ecuador and Guyana. The Company's strategy is focused on sustainable growth in production and reserves. Frontera is committed to conducting business safely, in a socially and environmentally responsible manner. Frontera's common shares trade on the Toronto Stock Exchange under the ticker symbol "FEC".

If you would like to receive News Releases via e-mail as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.

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, development and drilling plans including time and projected levels, the Company's exploration and development plans and objectives, timing and implementation of cost saving and efficiency initiatives and the timing of payment of dividends) are forward-looking statements. In particular, statements relating to "reserves" are deemed to be forward-looking statements since they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. 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: volatility in market prices for oil and natural gas; uncertainties associated with estimating and establishing oil and natural gas reserves; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; political developments in the countries where the Company operates; geological, technical, drilling and processing problems; fluctuations in foreign exchange or interest rates and stock market volatility; and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's AIF dated March 5, 2020 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 news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.

Non-IFRS Financial Measures

This news release contains the following financial terms that do not have standardized definitions in the International Financial Reporting Standards ("IFRS"): "operating EBITDA" and "net sales". These financial measures, together with measures prepared in accordance with IFRS, provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. The Company's determination of these non-IFRS measures may differ from other reporting issuers, and therefore are unlikely to be comparable to similar measures presented by other companies. Further, these non-IFRS measures should not be considered in isolation or as a substitute for measures of performance or cash flows prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity.

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.

EBITDA is a commonly used measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income taxes, finance income and depletion, depreciation and amortization expense.

Operating EBITDA represents the operating results of the Company's primary business, excluding the items noted above, fees paid on suspended pipeline capacity, payments under terminated pipeline contracts, restructuring, severance and other costs, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, and share-based compensation) and gains or losses arising form the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company.

The following table provides a complete reconciliation of net loss to Operating EBITDA:


Three months ended
December 31


Year ended
December 31

($M)

2019

2018


2019

2018







Net income (loss)

69,408

(116,631)


294,287

(259,083)







Finance income

(3,162)

(7,581)


(20,244)

(25,832)

Finance expenses

17,438

14,668


65,492

52,724

Income tax (recovery) expense

(42,540)

16,067


(147,727)

18,721

Depletion, depreciation and amortization

89,753

80,461


376,010

316,751

Impairment

3,389

117,017


63,580

305,586

Fees paid on suspended pipeline capacity


82,372

Payments under terminated pipeline contracts

59,040


74,618

Reversal of provision related to high-price clause

(41,079)


(62,911)

Loss on extinguishment of debt


25,628

Reclassification of currency translation adjustments

(2,753)


48,094

Share-based compensation

(124)

166


2,907

4,042

Restructuring, severance and other costs

2,994

8,092


11,945

14,592

Share of income from associates

(24,398)

(8,952)


(84,832)

(83,601)

Foreign exchange loss

8,812

13,087


10,264

3,375

Unrealized loss (gain) on risk management contracts

10,333

(31,392)


5,722

(107,337)

Other loss (income), net

6,680

832


(2,758)

4,741

Non-controlling interests

(1,531)

8,429


11,512

322

Operating EBITDA

137,052

109,471


586,158

412,802

1Net income (loss) attributable to equity holders of the Company

 











2019

2018

($M)

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

Financial and Operational results:









Operating EBITDA

137,052

124,586

179,665

144,855

109,471

92,676

124,667

85,988

 

Net Sales

Net sales is a non-IFRS subtotal that adjusts revenue to include realized gains and losses from risk management contracts while removing the cost of dilution activities. This is a useful indicator for management as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these risk management activities. The deduction of diluent cost is helpful to understand the Company's sales performance based on the net realized proceeds from production net of diluent, the cost of which is partially recovered when the blended product is sold. Net sales do not include the sales and purchases of oil and gas for trading as the gross margins from these activities are not considered significant or material to the Company's operations.  Refer to the reconciliation in the "Sales" section on page 9 of the MD&A.

Advisory Note Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with NI 51-101.  Complete reserves disclosure required in accordance with NI 51-101 is contained in the F1 Report filed on SEDAR.  Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this news release. There is no assurance that forecast prices and costs assumed in the Reserves Report, and presented in this news release, will be attained and variances from such forecast prices and costs could be material. The estimated future net revenue from the production of the disclosed oil and natural gas reserves in this news release does not represent the fair market value of these reserves.

The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve information set forth above are estimates only. In general, estimates of economically recoverable crude oil and natural gas reserves are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production with respect to its reserves will vary from estimates thereof and such variations could be material.

This news release includes non-standardized measures. Readers are cautioned that these measures, such as reserve life index should not be construed as alternative measures of financial performance. Such measures have been included to provide readers with additional means to evaluate the Company's performance but these non-standardized measures are not reliable indicators of the Company's future performance and therefore must not be relied upon unduly. The Company's method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Readers are cautioned that the information provided or derived by these measures should not be relied upon for investment purposes.

Well Test Results and Production Levels

Disclosure of well tests results in this news release should be considered preliminary until detailed pressure transient analysis and well-test interpretations have been completed. Hydrocarbons can be seen during the drilling of a well in numerous circumstances and do not necessarily indicate a commercial discovery or the presence of commercial hydrocarbons in a well. There is no representation by the Company that the disclosed well results included in this news release are necessarily indicative of long-term performance or ultimate recovery. As a result, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company or that such rates are indicative of future performance of the well.

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 news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.

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 cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy.

Definitions:

2P

Proved plus probable reserves

API

American Petroleum Institute

bbl(s)

Barrel(s) of oil

bbl/d

Barrel of oil per day

boe

Refer to "Boe Conversion" disclosure above

boe/d

Barrel of oil equivalent per day

C$

Canadian dollars

mcf

Thousand cubic feet

mmcf/d

Million cubic feet per day

Net Production

Net production after royalties represents the Company's working interest volumes, net of royalties and internal consumption

PDP

Proved Developed Producing

psi

per square inch

WI

Working Interest

 

"Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Cision View original content:http://www.prnewswire.com/news-releases/frontera-delivers-strong-fourth-quarter-and-2019-financial-and-operational-results-301018682.html

SOURCE Frontera Energy Corporation

View original content: http://www.newswire.ca/en/releases/archive/March2020/05/c5125.html

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