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From: LoneClone	3/2/2023 2:27:41 PM
	of 24755

News from Frontera indicates that things are going very well with their second deep well offshore Guyana which is JVed with OYl, in which I have a small position. Drilling is well ahead of schedule and there were oil shows in the shallower targets. Expect results from the deeper targets next month. LC

Share	RecommendKeepReply Mark as Last Read

From: LoneClone

3/10/2023 12:01:57 PM

HEADWATER EXPLORATION ANNOUNCES 2022 RESERVES, YEAR END 2022 OPERATING AND FINANCIAL RESULTS, OPERATIONS UPDATE AND DECLARES QUARTERLY DIVIDEND

newswire.ca

Headwater Exploration Inc. Mar 09, 2023, 17:43 ET

CALGARY, AB, March 9, 2023 /CNW/ - Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) announces its operating and financial results for the three months and year ended December 31, 2022. Selected financial and operational information is outlined below and should be read in conjunction with the audited financial statements and the related management's discussion and analysis ("MD&A"). These filings will be available at www.sedar.com and the Company's website at www.headwaterexp.com. In addition, readers are also directed to the Company's Annual Information Form for the year ended December 31, 2022, dated March 9, 2023, filed on SEDAR at www.sedar.com.

Financial and Operating Highlights

	Three months ended December 31,		Percent Change	Year ended December 31,		Percent Change
	2022	2021	Percent Change	2022	2021	Percent Change
Financial (thousands of dollars except share data)
Sales, net of blending (1) (4)	102,974	70,125	47	430,047	179,517	140
Adjusted funds flow from operations (2)	71,828	48,731	47	279,727	117,916	137
Per share - basic	0.31	0.24	29	1.23	0.59	108
- diluted	0.31	0.22	41	1.21	0.55	120
Cash flows provided by operating activities	66,448	47,753	39	283,925	111,656	154
Per share - basic	0.29	0.23	26	1.25	0.56	123
- diluted	0.28	0.22	27	1.23	0.52	137
Net income	39,789	27,927	42	162,109	45,828	254
Per share - basic	0.17	0.14	21	0.71	0.23	209
- diluted	0.17	0.13	31	0.70	0.21	233
Capital expenditures (1)	60,677	49,043	24	244,495	140,389	74
Adjusted working capital (2)				104,918	92,929	13
Shareholders' equity				543,335	397,791	37
Weighted average shares (thousands)
Basic	231,766	204,005	14	227,299	199,802	14
Diluted	235,305	220,958	6	230,755	215,861	7
Shares outstanding, end of period (thousands)
Basic				233,920	217,681	7
Diluted (5)				241,029	242,448	(1)
Operating (6:1 boe conversion)

Average daily production
Heavy crude oil (bbls/d)	13,536	9,377	44	11,411	6,665	71
Natural gas (mmcf/d)	11.5	6.4	80	8.2	4.4	86
Natural gas liquids (bbls/d)	99	-	100	57	2	2750
Barrels of oil equivalent (9) (boe/d)	15,546	10,449	49	12,841	7,393	74


Average daily sales (6) (boe/d)	15,568	10,459	49	12,843	7,390	74

Netbacks ($/boe) (3) (7)
Operating
Sales, net of blending (4)	71.90	72.88	(1)	91.74	66.57	38
Royalties	(13.51)	(11.34)	19	(18.17)	(9.62)	89
Transportation	(4.21)	(6.98)	(40)	(4.28)	(7.55)	(43)
Production expenses	(6.25)	(4.20)	49	(5.93)	(4.64)	28

Operating netback (3)	47.93	50.36	(5)	63.36	44.76	42
Realized losses on financial derivatives	2.96	1.41	110	0.01	0.35	(97)
Operating netback, including financial derivatives (3)	50.89	51.77	(2)	63.37	45.11	40
General and administrative expense	(1.14)	(1.23)	(7)	(1.38)	(1.48)	(7)
Interest income and other expense (8)	1.15	0.10	1050	0.76	0.09	744
Current tax expense	(0.75)	-	100	(3.07)	-	100
Adjusted funds flow netback (3)	50.15	50.64	(1)	59.68	43.72	37

(1)	Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
(2)	Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
(3)	Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release.
(4)	Heavy oil sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the annual financial statements blending expense is recorded within blending and transportation expense.
(5)	In-the-money dilutive instruments as at December 31, 2022 includes 6.1 million stock options with a weighted average exercise price of $2.74, 0.2 million restricted share units and 0.8 million performance share units.
(6)	Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. The Company's heavy crude oil sales volumes and production volumes differ due to changes in inventory. For the three months ended December 31, 2022, sales volumes comprised of 13,558 bbs/d of heavy oil, 11.5 mmcf/d of natural gas and 99 bbls/d of natural gas liquids (2021- heavy oil of 9,377 bbls/d and natural gas of 6.4 mmcf/d). For the year ended December 31, 2022, sales volumes comprised of 11,411 bbls/d of heavy oil, 8.2 mmcf/d of natural gas and 57 bbls/d of natural gas liquids (2021- heavy oil of 6,665 bbls/d, natural gas of 4.4 mmcf/d and natural gas liquids of 2 bbls/d).
(7)	Netbacks are calculated using average sales volumes.
(8)	Excludes unrealized foreign exchange gains/losses, accretion on decommissioning liabilities, interest on lease liability and interest on repayable contribution.
(9)	See '"Barrels of Oil Equivalent."

FOURTH QUARTER 2022 HIGHLIGHTS

Headwater declared its inaugural quarterly cash dividend of $0.10 per common share and returned $23.4 million to shareholders in January 2023.

Achieved average production of 15,546 boe/d (consisting of 13,536 bbls/d of heavy oil, 11.5 mmcf/d of natural gas and 99 bbls/d of natural gas liquids), an increase of 49% from the fourth quarter of 2021.

Generated significant adjusted funds flow from operations (1) of $71.8 million ($0.31 per basic share), representing an increase of 47% from the fourth quarter of 2021.

Achieved an operating netback (2) of $47.93/boe and an adjusted funds flow netback (2) of $50.15/boe.

Recognized net income of $39.8 million ($0.17 per share basic).

As at December 31, 2022, Headwater had working capital of $109.4 million, adjusted working capital (1) of $104.9 million and no outstanding bank debt.

YEAR ENDED DECEMBER 31, 2022 HIGHLIGHTS

Achieved average production of 12,841 boe/d (consisting of 11,411 bbls/d of heavy oil, 8.2 mmcf/d of natural gas and 57 bbls/d of natural gas liquids), an increase of 74% from 2021 annual production of 7,393 boe/d.

Adjusted funds flow from operations (1) was $279.7 million ($1.23 per basic share), representing an increase of 137% from 2021.

Achieved an operating netback (2) of $63.36/boe and an adjusted funds flow netback (2) of $59.68/boe.

Generated significant net income of $162.1 million, $0.71 per basic share, an increase of 254% from the comparable period in 2021.

Proved developed producing reserves increased by 69% to 16.6 mmboe from 9.8 mmboe.

Total proved reserves increased by 34% to 21.1 mmboe from 15.7 mmboe.

Proved plus probable reserves increased by 44% to 34.3 mmboe from 23.8 mmboe.

Achieved finding and development ("F&D") costs (2), including changes in future development costs of $21.42 on a proved developed producing basis, $24.70 per boe on a proved basis and $20.38 per boe on a proved plus probable basis.

Based on a 2022 adjusted funds flow netback (2) of $59.68/boe, achieved recycle ratios (2) of 2.8 on a proved developed producing basis, 2.4 on a proved basis and 2.9 on a proved plus probable basis.

(1)	Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
(2)	Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this press release.

EXPLORATION UPDATE

West Nipisi

Headwater validated a new pool discovery on our acreage by successfully drilling five wells in West Nipisi over the last four months. Results have exceeded expectations with on average 19 degree API oil and we are pleased to provide the following initial production details:

Well UWI	Zone	Initial 30-day average production rates ("IP30") (bbls/d)
100/12-08-078-09W5	Clearwater	300
100/13-08-078-09W5	Clearwater	288
100/05-08-078-09W5	Clearwater	276
100/13-16-078-09W5	Clearwater	201
100/14-16-078-09W5	Clearwater	128

A drilling rig has recently been moved back into this area and a stratigraphic test was conducted to assist with the validation of two additional prospective horizons. As a result of the stratigraphic test, two multi-laterals will be drilled prior to the end of the first quarter, testing these two previously untested zones.

Headwater has also continued to expand its land base during the first quarter of 2023 with the acquisition of an additional 31.5 sections of land in the West Nipisi area.

Greater Peavine

Two exploration wells in Peavine were drilled and placed on production in February of 2023. The first well 10-08-080-17W5 has a 14-day initial production rate of approximately 120 bbls/d of 13 degree API oil which is consistent with our expectations for the area. The second well at 11-08-080-17W5 finished recovering load fluid March 7th and is currently producing 200 bbls/d oil.

Our first exploration well at Seal, 13-06-083-15W5, was recently drilled and has been placed on production. This well is currently recovering load fluid and it exhibited strong geotechnical shows. We look forward to reporting back on its initial production results.

Marten Hills West

Headwater successfully drilled an exploration discovery well testing a previously untested Clearwater sand at 13-02-074-01W5, approximately 8 miles southeast of our Marten Hills West accumulation. The well recently came off load recovery and is producing at rates of approximately 175 bbls/d of oil. This previously untested Clearwater sand has the potential to materially increase our drilling inventory across our Marten Hills West land base.

Headwater continued delineation drilling on the southern extension of our Marten Hills West Clearwater A pool with 4 follow-up wells. The wells have exceeded expectations achieving average IP30's of 230 bbls/d of 20 degree API oil.

Testing of enhanced oil recovery is progressing on the West Marten Hills Clearwater A pool with two waterflood pilots. First water injection has recently commenced on our northern pilot at 13-07-76-02W5. Our second pilot at 16-22-75-02W5 will commence injection early in the third quarter of 2023.

Marten Hills Core

Headwater drilled 16 crude oil wells in the fourth quarter of 2022 and has drilled 6 crude oil wells quarter to date in 2023. The upper bench of 21-074-25W4 was developed in the fourth quarter with 11 wells placed on production with IP30's averaging approximately 300 bbls/d.

Waterflood implementation continues with 9 injection wells added in 2023. The increased injection has elevated stabilized waterflood production from 2,000 bbls/d to in excess of 2,500 bbls/d.

McCully

McCully was placed on production late November and is expected to deliver approximately $22 million of free cash flow (1) for the 2022/2023 winter season, with 64% of volumes hedged at Cdn$25.32/mmbtu. Headwater's structured hedging program for the McCully asset has protected the asset's cash flow against the highly volatile gas pricing experienced this winter.

(1) Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.

(2) McCully's winter season is estimated to be November 2022 to April 2023.

2023 GUIDANCE UPDATE

Headwater is re-confirming its previously released capital expenditures guidance of $200 million and corresponding annual average production at 18,000 boe/d. At strip pricing (1) the Company expects to generate adjusted funds flow from operations of $280 million with exit adjusted working capital of $90 million.

		2023 Guidance

2023 annual average production (boe/d)		18,000
Capital expenditures (2)		$200 million

WTI		US$75.21/bbl
WCS		Cdn$77.67/bbl
Adjusted funds flow from operations (3)		$280 million
Dividends		$94 million
Exit adjusted working capital (3)		$90 million

(1) Based on oil and gas commodity strip pricing at February 27, 2023

(2) Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.

(3) Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.

(4) For assumptions utilized in the above guidance see "Future Oriented Financial Information" within this press release.

FIRST QUARTER DIVIDEND

The Board of Directors of Headwater has declared a quarterly cash dividend to shareholders of $0.10 per common share payable on April 17, 2023, to shareholders of record at the close of business on March 31, 2023. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).

OUTLOOK

Since inception we have continued to maintain a positive working capital balance. When combined with our existing credit facility, it provides us with optionality to organically expand our Clearwater resource base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes.

Our exploration and pool extension results have continued to be robust with multiple new discoveries over the last several months. The discoveries and extensions continue to quantify the depth and quality of Headwater's drilling inventory which provides a pathway for continued success in the future.

Headwater continues to focus on total shareholder returns through a combination of growth and return of capital through a consistent and growing dividend stream. Based on current strip pricing and our projected growth rate, we anticipate having the optionality to materially increase our quarterly dividend in 2024 and beyond.

2022 RESERVE INFORMATION

Headwater currently has heavy oil reserves located in the Marten Hills and West Nipisi areas of Alberta and natural gas reserves in the McCully Field near Sussex, New Brunswick. GLJ Ltd. ("GLJ") assessed the Company's reserves in its report dated effective December 31, 2022 ("GLJ Report") which was prepared in accordance with standards of the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and is based on the average forecast prices as at December 31, 2022 of three independent reserves evaluation firms. Additional information regarding reserves data and other oil and gas information is included in Headwater's Annual Information Form for the year ended December 31, 2022, filed on SEDAR on March 9, 2023.

The following tables are a summary of Headwater's petroleum and natural gas reserves, as evaluated by GLJ, effective December 31, 2022. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained, and variances could be material. The recovery and reserves estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less than the estimates provided herein. Reserves information may not add due to rounding.

Reserves Summary

	Heavy	Shale	Conventional		Oil
	Oil	Gas	Gas	NGL	Equivalent
	Mbbls	MMcf	MMcf	Mbbls	MBOE

Proved developed producing	12,937	776	20,750	89	16,614
Proved developed non-producing	221	1,500	51	1	480
Proved undeveloped	4,006	-	145	1	4,032
Total proved	17,164	2,276	20,946	91	21,126
Total probable	11,422	758	9,453	45	13,169
Total proved plus probable	28,587	3,034	30,399	136	34,295

(1)	Reserves have been presented on gross basis which are the Company's total working interest share before the deduction of any royalties and without including any royalty interests of the Company.
(2)	Based on the average of GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2023.
(3)	Pursuant to the COGE Handbook, reported reserves should target at least a 90 percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Net Present Value of Future Net Revenue

	Before Income Tax and Discounted at					After Income Tax and Discounted at
	0 %	5 %	10 %	15 %	20 %	0 %	5 %	10 %	15 %	20 %
	$M	$M	$M	$M	$M	$M	$M	$M	$M	$M

Proved developed producing	602,841	542,500	490,424	448,535	414,689	518,371	466,231	420,704	384,152	354,730
Proved developed non-producing	19,856	16,687	14,333	12,572	11,222	15,297	12,803	10,958	9,590	8,551
Proved undeveloped	96,883	80,232	67,182	56,705	48,181	73,343	59,446	48,609	39,945	32,928
Total proved	719,579	639,419	571,939	517,812	474,092	607,011	538,480	480,271	433,686	396,209
Total probable	463,302	338,961	257,863	202,875	163,966	357,115	260,011	196,588	153,646	123,301
Total proved plus probable	1,182,881	978,380	829,802	720,687	638,058	964,126	798,491	676,859	587,332	519,510

(1)	Based on the average of GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2023.
(2)	All future net revenues are stated prior to provision for interest income and other, general and administrative expenses and after deduction of royalties, operating costs, estimated well and facility abandonment and reclamation costs and estimated future capital expenditures.
(3)	After-income tax net present value of future net revenue are based on Headwater's estimated tax pools as at December 31, 2022. The after-income tax net present value of Headwater's oil and natural gas properties reflects the income tax burden on the properties on a stand-alone basis and takes into account Headwater's existing tax pools. It does not consider tax planning.

Future Development Costs ("FDC")

The following is a summary of the estimated FDC required to bring proved undeveloped reserves and proved plus probable undeveloped reserves on production.

	Proved Reserves $M	Proved Plus Probable Reserves $M
2023	58,383	85,583
2024	33,249	70,470
Thereafter (1)	3,194	3,323
Total Undiscounted	94,826	159,376

(1) Future development capital after 2024 is associated with McCully gas plant optimization.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2022, reflected in the GLJ Report, using the average of commodity price forecasts from GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited effective as at January 1, 2023, to estimate the reserves volumes and associated values in the GLJ Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2022
FORECAST PRICES AND COSTS

Year	WTI Cushing Oklahoma ($US/Bbl)	MSW Light Crude 40o API ($Cdn/Bbl)	WCS Crude Oil Stream Quality at Hardisty ($Cdn/Bbl)	NYMEX Henry Hub ($US/ MMBtu)	Natural Gas AECO-C Spot ($Cdn/ MMBtu)	Algonquin City Gates Natural Gas ($US/MMBtu)	McCully Gas Price (1) ($Cdn/Mcf)	Inflation Rates %/Year	Exchange Rate (2) ($Cdn/$US)

Forecast (3)
2023	80.33	103.77	76.54	4.74	4.23	7.92	14.68	0.0	0.75
2024	78.50	97.74	77.75	4.50	4.40	6.38	11.93	2.3	0.77
2025	76.95	95.27	77.54	4.31	4.21	6.19	11.53	2.0	0.77
2026	77.61	95.58	80.07	4.40	4.27	6.28	9.99	2.0	0.77
2027	79.16	97.07	81.89	4.49	4.34	6.37	10.12	2.0	0.78
2028	80.75	99.01	84.02	4.58	4.43	6.46	10.28	2.0	0.78


Thereafter Escalation rate of 2.0%

Notes:
(1)	The forecast McCully gas price is used by GLJ in calculating the net present value of Headwater's future natural gas net revenues from the McCully field. The McCully gas price is determined by adjusting the forecast AGT gas prices to reflect the expected premiums received at Headwater's delivery point, transportation costs, as applicable, heat content and marketing conditions. The McCully gas price in years 2023 – 2025 reflects only the winter producing months (January to April and November to December) or correlate to the intermittent production strategy employed by the Company to capture seasonal premium pricing. After 2025, the GLJ Report assumes Headwater produces volumes from its reserves continuously over the year and as such, McCully pricing reflects the full year.
(2)	The exchange rate used to generate the benchmark reference prices in this table.
(3)	As at December 31, 2022.

Additional corporate information can be found in the Company's corporate presentation and on Headwater's website at www.headwaterexp.com

FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words "guidance", "initial, "anticipate", "scheduled", "can", "will", "prior to", "estimate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation, the intent to report the results from certain exploration wells; the expectation that two multi-laterals will be drilled prior to the end of the first quarter testing two previously untested zones; the 2023 guidance related to expected annual average production, capital expenditures and the breakdown thereof, adjusted funds flow from operations and exit adjusted working capital; the expectation that the previously untested Clearwater sand at 13-02-074-01W5 has the potential to materially increase the Company's drilling inventory across the Marten Hills West land base; the expected timing of testing of enhanced oil recovery at Marten Hills West; the expectation of McCully performance through the 2022/2023 winter season; the expectation that the Company's positive working capital balance and credit facility will provide Headwater the optionality to organically expand its Clearwater resource base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes; the expectation that discoveries and extensions have continued to quantify the depth and quality of Headwater's drilling inventory which is expected to provide a pathway for continued success in the future; the expectation to have the optionality to increase the quarterly dividend in 2024 and beyond at current strip pricing and with the Company's projected growth rate. The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, receipt of required regulatory approvals, the success of future drilling, development and waterflooding activities, the performance of existing wells, the performance of new wells, Headwater's growth strategy, general economic conditions, availability of required equipment and services, prevailing equipment and services costs, prevailing commodity prices and certain other guidance assumptions as detailed below under the heading "Future Oriented Financial Information" as set out below. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; disruptions to the Canadian and global economy resulting from major public health events, the Russian-Ukrainian war and the impact on the global economy and commodity prices; the impacts of inflation and supply chain issues and steps taken by central banks to curb inflation; pandemic, war, terrorist events, political upheavals and other similar events; events impacting the supply and demand for oil and gas including actions taken by the OPEC + group; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Refer to Headwater's most recent Annual Information Form dated March 9, 2023, on SEDAR at www.sedar.com, and the risk factors contained therein.

FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of the Company as of the date

hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2023 has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. The assumptions used in the 2023 guidance include: AGT US$7.61/mmbtu, foreign exchange rate of US$/Cdn$ of 0.74, blending expense of WCS less $2.00, royalty rate of 17%, operating and transportation costs of $11.50/boe, financial derivatives gains of $1.00/boe, G&A and interest income and other expense of $1.05/boe and cash taxes of $6.00/boe. The AGT price is the average price for the winter producing months in the McCully field which include January to April and November to December. 2023 annual production guidance comprised of: 16,390 bbls/d of heavy oil, 60 bbls/d of natural gas liquids and 9.3 mmcf/d of natural gas.

DIVIDENDS: The amount of future cash dividends paid by the Company, if any, will be subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, adjusted funds from operations, fluctuations in commodity prices, production levels, capital expenditure requirements, acquisitions, debt service requirements and debt levels, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the Board will adjust the Company's dividend policy from time to time and, as a result, future cash dividends could be reduced or suspended entirely.

BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The term "boe" (or barrels of oil equivalent) and "Mcf" (or thousand cubic feet of natural gas equivalent) may be misleading, particularly if used in isolation. A boe and Mcf conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

INITIAL PRODUCTION ("IP") RATES: References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.

NON-GAAP AND OTHER FINANCIAL MEASURES

In this press release, we refer to certain financial measures and ratios (such as free cash flow, total sales, net of blending and capital expenditures, adjusted funds flow netback, operating netback and operating netback, including financial derivatives, F&D costs and recycle ratio) which do not have any standardized meaning prescribed by IFRS. Our determinations of these measures may not be comparable with calculations of similar measures for other issuers. In addition, this press release contains the terms adjusted funds flow from operations and adjusted working capital, which are considered capital management measures. The term cash flow in this press release is equivalent to adjusted funds flow from operations.

Non-GAAP Financial Measures

Free cash flow

Management utilizes free cash flow to assess the amount of funds available for future capital allocation decisions. It is calculated as adjusted funds flow from operations net of capital expenditures.

	Three months ended December 31,		Year ended December 31,
	2022	2021	2022	2021
	(thousands of dollars)		(thousands of dollars)
Adjusted funds flow from operations	71,828	48,731	279,727	117,916
Capital expenditures	(60,677)	(49,043)	(244,495)	(140,389)
Free cash flow	11,151	(312)	35,232	(22,473)

Total sales, net of blending

Management utilizes total sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the annual financial statements blending expense is recorded within blending and transportation expense.

	Three months ended December 31,		Year ended December 31,
	2022	2021	2022	2021
	(thousands of dollars)		(thousands of dollars)
Total sales	109,377	75,287	458,379	190,940
Blending expense	(6,403)	(5,162)	(28,332)	(11,423)
Total sales, net of blending expense	102,974	70,125	430,047	179,517

Capital expenditures

Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company's annual financial statements netted by the government grant.

	Three months ended December 31,		Year ended December 31,
	2022	2021	2022	2021
	(thousands of dollars)		(thousands of dollars)
Cash flows used in investing activities	61,957	47,047	232,056	109,127
Proceeds from government grant	780	-	1,988	-
Restricted cash	5,000	1,248	-	1,477
Change in non-cash working capital	(5,223)	748	14,879	29,785
Government grant	(1,837)	-	(4,428)	-
Capital expenditures	60,677	49,043	244,495	140,389

Capital Management Measures

Adjusted Funds Flow from Operations

Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. In addition to being a capital management measure, adjusted funds flow from operations is used by management to assess the performance of the Company's oil and gas properties. Adjusted funds flow from operations is an indicator of operating performance as it varies in response to production levels and management of production and transportation costs. Management believes that by eliminating changes in non-cash working capital and deducting current income taxes, adjusted funds flow from operations is a useful measure of operating performance. While current income taxes will not be paid until 2023, management believes adjusting for current income taxes in the period incurred is a better indication of the funds generated by the Company.

	Three months ended December 31,		Year ended, December 31,
	2022	2021	2022	2021
	(thousands of dollars)		(thousands of dollars)
Cash flows provided by operating activities	66,448	47,753	283,925	111,656
Changes in non–cash working capital	6,455	978	10,195	6,260
Current income taxes	(1,075)	-	(14,393)	-
Adjusted funds flow from operations	71,828	48,731	279,727	117,916

Adjusted Working Capital

Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity.

	Year ended December 31,
	Year ended December 31,
	2022	2021
	(thousands of dollars)
Working capital	109,433	89,775
Contribution receivable (long-term)	1,104	-
Repayable contribution	(6,720)	-
Financial derivative receivable	(419)	(770)
Financial derivative liability	1,520	3,924
Adjusted working capital	104,918	92,929

Non-GAAP Ratios

Adjusted funds flow netback, operating netback and operating netback, including financial derivatives

Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period.

Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. The sales volumes exclude the impact of purchased condensate. Operating netback, including financial derivatives is defined as operating netback plus realized gains or losses on financial derivatives.

Adjusted funds flow per share

Adjusted funds flow per share is a non-GAAP ratio and is used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding on a basic or diluted basis.

F&D costs per boe

F&D costs is used as a measure of capital efficiency. The F&D cost calculation includes all capital expenditure (exploration and development) for that period plus the change in future development capital ("FDC") for that period based on the evaluations completed by GLJ as at December 31, 2021 as compared to December 31, 2022. This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions and production for that same period. Total proved developed producing F&D is calculated as follows = ($244.5 million (2022 capital expenditures) + $1.5 million (change in FDC associated with proved developed reserves)) / (16,614 mboe – 9,818 mboe +4,687 mboe) = $21.42 per boe. Total proved F&D is calculated as follows = ($244.5 million (2022 capital expenditures) + $6.2 million (change in FDC associated with proved reserves)) / (21,126 mboe – 15,663 mboe +4,687 mboe) = $24.70 per boe. Total proved plus probable F&D is calculated as follows = ($244.5 million (2022 capital expenditures) + $65.0 million (change in FDC associated with proved plus probable reserves)) / (34,295 mboe – 23,790 mboe +4,687 mboe) = $20.38 per boe.

Recycle ratio

Recycle ratio is used as a measure of capital efficiency. Recycle ratio is calculated as the Company's adjusted funds flow netback divided by F&D costs per boe.

Per boe numbers

This press release represents various results on a per boe basis including Headwater average realized sales price, net of blending, financial derivatives gains (losses) per boe, royalty expense per boe, transportation expense per boe, production expense per boe, general and administrative expenses per boe, interest income and other expense per boe and current taxes per boe. These figures are calculated using sales volumes.

SOURCE Headwater Exploration Inc.

For further information: HEADWATER EXPLORATION INC., Mr. Neil Roszell, P. Eng., Chairman and Chief Executive Officer; HEADWATER EXPLORATION INC., Mr. Jason Jaskela, P.Eng., President and Chief Operating Officer; HEADWATER EXPLORATION INC., Ms. Ali Horvath, CPA, CA, Vice President, Finance and Chief Financial Officer, info@headwaterexp.com, (587) 391-3680

RecommendKeepReply Mark as Last Read Read Replies (1)

To: LoneClone who wrote (24588)	3/10/2023 12:34:14 PM
From: LoneClone	of 24755

In response to that PR, BMI put out a new analyst report on HWX. Citing the production and cash flow beat, the exploration results, and the new land they acquired, BMO said HWX remains one of its top picks in the small/midcap space, and reiterated an Outperform rating with a $10 target. While mentioning HWX's first dividend being declared, they muse about the possibility of a dividend increase later in the year. LC

Share	RecommendKeepReply Mark as Last Read

From: LoneClone

3/29/2023 12:38:28 PM

Southern Energy Announces 2023 Capital Budget and Gwinville Operational Update, Year End Reserves Update and Joint Broker Appointments

accesswire.com

Wednesday, March 29, 2023 2:02 AM

CALGARY, AB / ACCESSWIRE / March 29, 2023 / Southern Energy Corp. ("Southern" or the "Company") (TSXV:SOU)(AIM:SOUC)(OTCQX:SOUTF) is pleased to announce its:

2022 Year End Reserves Upgrade:
- Highlights of the Company's year end independent oil and gas reserves evaluation as at December 31, 2022 (the "NSAI Report") include:
  - an increase in proved developed producing ("PDP")reserves of 25% to 6.2 MMboe
  - an increase in total proved ("1P") reserves of 44% to 14.1 MMboe
  - an increase in total proved plus probable ("2P") reserves by 31% to 25.5 MMboe in 2022
  - before-tax net present value ("NPV") of 2P reserves, discounted at 10% ("NPV10"), of $142.5 million (an increase of 61% on year end 2021)
Gwinville Operational Update:
- The Company announces the completion of its current drilling campaign of seven horizontal wells
- Through technical improvements, Southern has reduced the average time from spud to total depth of its Gwinville wells from approximately 21 days to between 9-12 days and averaging 80-100% lateral placement in the high-graded porosity interval
Capital Budget Update:
- In response to the current low natural gas prices, Southern plans to moderate the Gwinville organic growth program from the planned capital budget of US$101.0 million announced in November 2022 to approximately US$55.0 million
- Under its revised capital plan, Southern will have drilled seven horizontal wells at the Gwinville asset, completed three wells and have four wells remain as drilled but uncompleted ("DUCs") to be brought on in the future once natural gas prices are more supportive
Broker Appointments:
- Stifel Nicolaus Europe Limited and Tennyson Securities have both been appointed as the Company's joint corporate brokers with immediate effect

Ian Atkinson, President & Chief Executive Officer of Southern, commented:

"Although the drop in natural gas prices has brought us to the decision to moderate our Gwinville capital program, the overall impact of the applied learnings from the 2022 appraisal program have paid off and we are happy with the early results. In the current program we have drilled seven horizontal wells with longer laterals than the original appraisal wells in half the time on a per well basis and proven that the re-interpretation of our 3D seismic has improved our overall ability to stay within the targeted zone. We have positioned ourselves for the inevitable rebound in natural gas prices and look forward to moving equipment and manpower back into the Gwinville field quickly as price recovery occurs to re-initiate our organic growth plans and take advantage of maximising cashflows at the opportune time."

Gary McMurren, Chief Operating Officer, commented:

"We are excited to report another year of material reserves growth in all major categories for the Company, highlighted by conservative additions to our Gwinville horizontal Selma Chalk inventory following our successful appraisal program in 2022. In our current development program, we will be testing two Lower Selma Chalk and two City Bank horizontal laterals with our modern completion design. The Lower Selma Chalk has only minimal reserve bookings in this year's report, and we have yet to book any City Bank development reserves, so upon completion of these horizons over the next few months, we expect to continue to add significant and predictable reserves growth in Gwinville for years to come.

The NSAI Report highlights the extensive running room and future development potential of only one of our existing core assets which will deliver long term sustainable free funds flow and organic growth. Further work is expected to unlock additional value for Southern shareholders, with the potential to significantly grow reserves in our portfolio in a short time frame.

With an average operating cost in 2022 of under $0.80/Mcfe, Southern has some of the highest margin natural gas assets in North America, which continues to benefit the business model and provide strong cashflow for the Company."

Gwinville Operational Update

The Company is pleased to summarize the results of the current capital program to date as compared to the 19-3 padsite appraisal program:

Well Name	Zone	Spud to TD (days)	Lateral Length (ft)	% in zone	Frac Stages	Total Proppant (million lbs)	Proppant Loading (lb/ft)	IP30 (MMcf/d)
Historic Appraisal Drilling
19-3 #2	Upper Selma	20.2	3,498	90	41	6.6	1,884	6.5
19-3 #3	Upper Selma	18.5	4,146	50	44	7.0	1,700	3.6
19-3 #4	Upper Selma	22.2	4,623	50	50	8.0	1,650	4.0
Current Drilling Campaign
18-10 #1	City Bank	14.4	5,744	100	50	10.0	1,747	TBD
18-10-#2	Upper Selma	12.0	4,699	50	43	8.6	1,830	3.3
18-10 #3	Upper Selma	11.6	5,091	80	44	9.0	1,771	TBD
14-6 #3	Upper Selma	10.4	5,525	85	Not yet completed
14-6 #4	Lower Selma	9.4	5,521	100	Not yet completed
13-13 #2	Lower Selma	9.3	5,302	96	Not yet completed
13-13 #3	City Bank	12.9	5,118	100	Not yet completed

Gwinville 18-10 Padsite

The Company is pleased to report the initial 30-day production rate ("IP30") on the first well of the 18-10 pad out of a total of seven wells drilled to date in the capital program. The 18-10 #2 Upper Selma Chalk well recently reached an IP30 of 3.3 MMcf/d, which is similar to the 19-3 #3 and #4 appraisal wells, and below early type curve expectations for these Generation 3 well designs. The well encountered some unpredicted faulting and was drilled with only 50% of that lateral length within the high-grade porosity interval. Although below Generation 3 type curve estimates, the result is representative of a well with an effective lateral length in the high-graded porosity interval of less than 2,600 feet.

The 18-10 #3 Upper Selma Chalk well achieved approximately 80% of the lateral within the high-grade porosity interval and was completed with a 44-stage stimulation. The Company experienced a mechanical wellbore integrity issue during the completion and plans to perform remedial work on the well and establish production in Q2 or Q3 of this year.

The 18-10 #1 City Bank well was drilled to a lateral length of approximately 5,744 feet with 100% of the lateral drilled in the target interval. The well was successfully stimulated with a 50-stage completion operation and is in early stages of completion flowback currently producing flowback water at 5% of load recovery. Southern does not expect to see peak gas rates until the well has recovered approximately 20% of load fluid based on historically stimulated vertical and Generation 1 horizontal wells in the City Bank reservoir at which time the Company will report on initial production. The Company is encouraged by the early results and looks to add significant net asset value to the reserve books in 2023 as no proven undeveloped or probable locations have been attributed to the City Bank zone to-date.

Gwinville Drilling Efficiencies

As a follow-up to the three well Upper Selma Chalk appraisal program from Q2 2022, which has recovered approximately 55% of upfront capital in less than nine months of production, Southern identified two major technical improvements to be employed on future activity. The re-interpretation of the 3D seismic to provide a higher resolution assessment of the reservoir, coupled with the utilization of a rotary steerable downhole drilling assembly that allows for immediate and more responsive corrections, has resulted in a significant improvement to the lateral length drilled in the high porosity interval and a significant reduction in overall drilling times. Utilizing these changes, Southern has reduced the average time from spud to total depth of these wells from approximately 21 days to between 9-12 days and averaging 80-100% lateral placement in the high-graded porosity interval. The learnings and cost savings achieved early in this program are expected to translate into all future Gwinville drilling.

The Company's first padsite in the winter program was the 18-10 pad, which has two Upper Selma Chalk laterals and the first City Bank lateral. Next, the rig drilled the 14-06 pad that contained one Upper Selma Chalk lateral, and the first Lower Selma Chalk lateral. The rig has recently finished drilling the 13-13 pad with the second City Bank and Lower Selma Chalk laterals. The drilling rig has been released and the final four laterals will remain as DUCs until natural gas prices are more supportive of capital spending on organic growth.

Capital Budget Update

In response to the current low natural gas prices and guided by principles focused on full-cycle value creation, Southern plans to moderate the Gwinville organic growth program from the planned capital budget of US$101.0 million announced in November 2022 to approximately US$55.0 million. Under its revised capital plan, Southern will have drilled seven horizontal wells at the Gwinville asset, completed three wells and have four wells remain as DUCs to be brought online in a higher natural gas price environment. These changes to the program at Gwinville will preserve capital, allow Southern the optionality to bring on high volume natural gas production at opportune natural gas prices and retain an inventory of high value development targets.

Year End Reserves Upgrade

Southern is pleased to announce selected highlights of the Company's year end independent oil and gas reserves evaluation as at December 31, 2022. The NSAI Report was prepared by independent qualified reserves evaluator, Netherland, Sewell and Associates, Inc. ("NSAI"). All currency amounts are in United States dollars (unless otherwise stated) and comparisons refer to December 31, 2021. Financial information contained herein is based on the Company's unaudited results for the year ended December 31, 2022 and is subject to change. The Company anticipates announcing its fourth quarter and audited year end 2022 financial results and filing an annual information form ("AIF") for the year ended December 31, 2022, in April 2023.

Highlights:

RLI

PDP replacement of 153%1P replacement of 484%2P replacement of 656%

PDP: $51.6 million (59% increase on year end 2021)1P: $85.3 million (59% increase on year end 2021)2P: $142.5 million (61% increase on year end 2021)

In addition, inter alia, to the summary information disclosed in this press release, more detailed information regarding Southern's oil and gas reserves will be includedin the Company's AIF to be filed on SEDAR ( www.sedar.com).

2022 Independent Qualified ReserveEvaluation

The following tables highlight the findings of the NSAI Report, which was prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101")and the most recent publication of the Canadian Oil and Gas Evaluation ("COGEH"). All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expensesand after deductionof royalties, operating costs, estimated well abandonment and reclamation costs, and estimatedfuture capital expenditures. The NSAI Report was based on the average forecast pricing of the following four independent external reserves evaluators: GLJ Ltd, Sproule Associates Limited, McDaniel & Associates Consultants Ltd and Deloitte LLP. Additional reserves information as required under NI 51-101 will be included in Southern's AIF, which will be filed on SEDAR in April 2023. The numbers in the tables below may not add due to rounding.

Summary of Reserves Volumes as at December 31, 2022

The Company's reserve volumes and undiscounted future development capital costs are summarized below as at December 31, 2022:

SUMMARY OF RESERVE VOLUMES (1)	Light and Medium Oil (Mbbls)	Condensate (Mbbls)	NGL (Mbbsl)	Conventional Natural Gas (MMcf)	Total Mboe	FDC Costs ($M)
Proved Developed Producing	79	203	49	35,281	6,211	-
Proved Developed Non-Producing	55	65	5	9,793	1,757	8,136
Proved Undeveloped	-	369	113	34,010	6,150	71,567
Total Proved	134	637	166	79,084	14,117	79,702
Probable	41	188	13	66,579	11,338	84,832
Total Proved Plus Probable	175	825	178	145,663	25,456	164,533

(1) Gross working interest reserves before royalty deductions.

The following table outlines the changes in Southern's reserves and reserve life index as at December 31, 2022 compared to December 31, 2021:

CHANGE IN RESERVES AND RESERVE LIFE INDEX(1,2)	2022	2021	% Change
Reserves (Mboe)
Proved Developed Producing	6,211	5,707	25%
Total Proved	14,117	10,479	44%
Total Proved Plus Probable	25,456	20,178	31%
PDP as % of 2P	24%	28%	(14%)
1P as % of 2P	55%	52%	7%
Reserve Life Index (years)
Proved Developed Producing	8.2	8.5	(4%)
Total Proved	11.5	15.6	(26%)
Total Proved Plus Probable	15.1	18.1	(17%)

(1) Percent change includes 2022 actual production of 948.4 Mboe

(2) The RLI as at December 31, 2022 is calculated as gross working interest reserves divided by the projected annual production forecast in each reserve category for 2023. See "Disclosure of Oil and Gas Information"

Southern's total 2P reserves increased by 31% to 25.5 MMboe resulting in a 2P reserve life index of 15.1 years on projected annual 2P production for 2023. Southern's 2022 Selma Chalk horizontal well appraisal program helped the Company achieve a 25% increase in PDP reserves to 6.2 MMboe.

Net Present Value of Future Net Revenue as at December 31, 2022

The following table summarizes the net present value, at varying discount rates, of the Company's reserves (before-tax) as at December 31, 2022. The reserves value on a $/boe basis, discounted at 10% per year, is also summarized for each category.

NET PRESENT VALUE BEFORE-TAX	0% (M$)	10% (M$)	20% (M$)	Unit Value(1) Before Income Tax, Discounted at 10%/year ($/boe)
Proved Developed Producing	84,730	51,617	38,860	10.61
Proved Developed Non-Producing	29,510	11,376	6,587	8.42
Proved Undeveloped	73,834	22,343	4,400	4.51
Total Proved	188,074	85,336	49,847	7.64
Probable	180,679	57,191	24,546	6.36
Total Proved Plus Probable	368,753	142,528	74,393	7.07

(1) Unit values are based on net reserves. Net reserves are the Company's working interest reserves after deduction of royalties

Forecast Prices Used in Estimates

The following table outlines the forecasted future prices used by NSAI in its evaluation of the Company's reserves at December 31, 2022, for the NSAI Report, which are based on a four-consultant average price forecast, as detailed above. The forecast cost and price assumptions assume increases in wellhead selling prices and consider inflation with respect to future operating and capital costs.

FUTURE COMMODITY PRICE FORECAST	WTI Cushing Oklahoma $/bbl	NYMEX Henry Hub $/MMBtu
2023	80.25	4.93
2024	78.19	4.66
2025	76.10	4.42
2026	76.96	4.50
2027	78.50	4.59
2028	80.07	4.68
2029	81.67	4.78
2030	83.30	4.87
2031	84.96	4.97
2032	86.67	5.08
Thereafter	+ 2.0%/year	+ 2.0%/year

Reserves Reconciliation

The following table sets out the reconciliation of Southern's gross reserves based on forecast prices and costs by principal product type as at December 31, 2022 relative to December 31, 2021. The majority of 1P and 2P reserves increases, year-on-year, came from recognition of the Gwinville Selma Chalk horizontal locations from infill drilling.

RESERVES(1) RECONCILIATION	PDP (Mboe)	1P (Mboe)	Probable (Mboe)	2P (Mboe)
December 31, 2021	5,707	10,479	9,699	20,178
Discoveries	-	-	-	-
Extensions	-	-	-	-
Infill Drilling	624	3,747	1,281	5,028
Improved Recovery	-	-	-	-
Technical Revisions(2)	(34)	(30)	259	229
Acquisitions	43	55	1	56
Dispositions	(40)	(40)	(22)	(62)
Economic Factors	860	856	120	976
Production(3)	(948)	(948)	-	(948)
December 31, 2022	6,211	14,117	11,338	25,456

(1) Gross working interest reserves before royalty deductions

(2) Technical revisions also include reserves associated with changes in operating costs and commodity price offsets

(3) Produced volumes for the year ended December 31, 2022 are internally estimated

Appointment of Joint Broker

Southern is pleased to report that Stifel Nicolaus Europe Limited and Tennyson Securities have both been appointed as the Company's joint corporate brokers with immediate effect, alongside Canaccord Genuity. Strand Hanson remain the Company's Nominated and Financial Adviser.

Corporate Presentation

A new corporate presentation dated March 2023 is now available on the Company website at www.southernenergycorp.com.

For further information, please contact:

Southern Energy Corp.
Ian Atkinson (President and CEO)
+1 587 287 5401

Calvin Yau (CFO)
+1 587 287 5402

Strand Hanson Limited - Nominated & Financial Adviser
James Spinney / James Bellman
+44 (0) 20 7409 3494

Canaccord Genuity - Joint Broker
Henry Fitzgerald-O'Connor / James Asensio
+44 (0) 20 7523 8000

Stifel Nicolaus Europe Limited - Joint Broker
Callum Stewart / Ashton Clanfield
+44 (0) 20 7710 7600

Tennyson Securities - Joint Broker
Peter Krens / Pav Sanghera
+44 (0) 20 7186 9033

Camarco
Owen Roberts / Billy Clegg / Hugo Liddy
+44 (0) 20 3757 4980

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulation (EU) No. 596/2014 as it forms part of United Kingdom domestic law by virtue of the European Union (Withdrawal) Act 2018, as amended.

About Southern Energy Corp.

Southern Energy Corp. is a natural gas exploration and production company. Southern has a primary focus on acquiring and developing conventional natural gas and light oil resources in the southeast Gulf States of Mississippi, Louisiana, and East Texas. Our management team has a long and successful history working together and have created significant shareholder value through accretive acquisitions, optimization of existing oil and natural gas fields and the utilization of re-development strategies utilizing horizontal drilling and multi-staged fracture completion techniques.

Qualified Person's Statement

Gary McMurren, Chief Operating Officer, who has over 23 years of relevant experience in the oil industry and has approved the technical information contained in this announcement. Mr. McMurren is registered as a Professional Engineer with the Association of Professional Engineers and Geoscientists of Alberta and received a Bachelor of Science degree in Chemical Engineering (with distinction) from the University of Alberta.

Disclosure of Oil and Gas Information

AIF. The reserves information and data provided in this press release presents only a portion of the disclosure required under NI 51-101. Southern's Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 dated effective as at December 31, 2022, which will include further disclosure of Southern's oil and gas reserves and other oil and gas information in accordance with NI 51-101 and COGEH forming the basis of this press release, will be included in the AIF which will be available on SEDAR at www.sedar.com in April 2023.

Unit Cost Calculation. Natural gas liquids volumes are recorded in barrels of oil (bbl) and are converted to a thousand cubic feet equivalent (Mcfe) using a ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl). 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). Mcfe and boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl or a Mcfe conversion ratio of 1 bbl:6 Mcf is based in an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of oil as compared with natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf:1 bbl or a Mcfe conversion ratio of 1 bbl:6 Mcf may be misleading as an indication of value.

Product Types. Throughout this press release, "crude oil" or "oil" refers to light and medium crude oil product types as defined by NI 51-101. References to "NGLs" throughout this press release comprise pentane, butane, propane, and ethane, being all NGLs as defined by NI 51-101. References to "natural gas" throughout this press release refers to conventional natural gas as defined by NI 51-101.

Short-Term Production. References in this press release to peak rates, IP30 and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Southern.

Reserves and Future Net Revenue Disclosure. All reserves values, future net revenue and ancillary information contained in this press release are derived from the NSAI Report unless otherwise noted. All reserve references in this press release are "Company gross reserves". Company gross reserves are the Company's total working interest reserves before the deduction of any royalties payable by the Company. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by NSAI in evaluating Southern's reserves will be attained and variances could be material. All reserves assigned in the NSAI Report are located in the State of Mississippi and presented on a consolidated basis.

All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The recovery and reserve estimates of Southern's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only.

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. 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. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101, Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.

Oil and Gas Metrics. This press release contains metrics commonly used in the oil and natural gas industry, such as development capital.

"Development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital presented herein excludes land and capitalized administration costs but includes the cost of acquisitions and capital associated with acquisitions where reserve additions are attributed to the acquisitions. These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Southern's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

Abbreviations

bbl	barrels
Mbbls	thousand barrels
bbls/d	barrels perday
$M	thousands of US dollars
boe	barrels of oil equivalent
Mboe	thousand barrels of oil equivalent
MMboe	million barrels of oil equivalent
boe/d	barrels of oil equivalent per day
Bcfe	billion cubic feet equivalent
Mcfe	million cubic feet equivalent
GJ	gigajoule
Mcf	thousand cubicfeet
Mcf/d	thousand cubicfeet per day
MMcf/d	million cubicfeet per day
MMBtu	million British Thermal Units
NYMEX - HH	New York Mercantile Exchange - Henry Hub
WTI	West TexasIntermediate, the reference price paid in U.S. dollarsat Cushing, Oklahoma for the crudeoil standard grade
FDC	future development costs

Forward Looking Information

This press release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Southern's business strategy, objectives, strength and focus; future consolidation activity and organic growth; future intentions with respect to return of capital; oil and natural gas production levels, decline rates, free funds flow; anticipated operational results for 2023 including, but not limited to, estimated or anticipated production levels, capital expenditures and drilling plans and locations; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; the ability of the Company to achieve drilling success consistent with management's expectations; risk management activities; estimates as to preliminary unaudited financial information for December 31, 2022; and the source of funding for the Company's activities including development costs. Statements relating to production, reserves, recovery, replacement, costs and valuation are also deemed to be forward-looking statements, as 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.

The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Southern, including those relating to: the business plan of Southern; the timing of and success of future drilling, development and completion activities; the geological characteristics of Southern's properties; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products; the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the drilling, completion and tie-in of wells being completed as planned; the performance of new and existing wells; the application of existing drilling and fracturing techniques; prevailing weather and break-up conditions; royalty regimes and exchange rates; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; the accuracy of Southern's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Southern's ability to execute its plans and strategies.

Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Southern can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: incorrect assessments of the value of benefits to be obtained from exploration and development programs; changes in the financial landscape both domestically and abroad, including volatility in the stock market and financial system; wars (including Russia's war in Ukraine); risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); commodity prices; increased operating and capital costs due to inflationary pressures; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses; health, safety, litigation and environmental risks; inflationary risks; access to capital; and the COVID-19 pandemic. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to react to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the annual information form for the year ended December 31, 2021, the management's discussion and analysis for the period ended September 30, 2022 (the "MD&A") and other continuous disclosure documents for additional risk factors relating to Southern, which can be accessed either on Southern's website at www.southernenergycorp.com or under the Company's profile on www.sedar.com.

The forward-looking statements contained in this press release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Southern's prospective results of operations, operating costs and margins, free funds flow and expectations regarding continued significant and predictable reserves growth, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was approved by management as of the date of this document and was provided for the purpose of providing further information about Southern's future business operations. Southern and its management believe that FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Southern disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein.

Specified Financial Measures. This press release provides various financial measures that do not have a standardized meaning prescribed by IFRS, including non-IFRS financial measures, non-IFRS financial ratios and capital management measures. These specified financial measures may not be comparable to similar measures presented by other issuers. Southern's method of calculating these measures may differ from other companies and accordingly, they may not be comparable to measures used by other companies. Operating netback is not a recognized measure under IFRS. Readers are cautioned that specified financial measures should not be construed as alternatives to other measures of financial performance calculated in accordance with IFRS. These specified financial measures provide additional information that management believes is meaningful in describing the Company's operational performance, liquidity and capacity to fund capital expenditures and other activities. Please see below for a brief overview of all specified financial measures used in this release and refer to the Company's MD&A for additional information relating to specified financial measures, which is available on the Company's website at www.southernenergycorp.com and filed on SEDAR.

"Operating Netback" (non-IFRS financial measure) equals total oil and natural gas sales less royalties, production taxes, operating expenses, transportation costs and realized gain / (loss) on derivatives. Management considers operating netback an important measure to evaluate its operational performance, as it demonstrates field level profitability relative to current commodity prices.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE: Southern Energy Corp.

RecommendKeepReply Mark as Last Read Read Replies (1)

To: LoneClone who wrote (24590)

3/29/2023 12:49:57 PM

From: LoneClone

Prairie Provident Resources Announces Transformative Recapitalization Transactions

ca.finance.yahoo.com

Prairie Provident Resources Inc.
Wed, March 29, 2023 at 5:06 a.m. PDT·48 min read

Transactions include Senior Credit Facility Extension, New Second Lien Financing, Repayment of Subordinated Notes with Equity and related Warrant Exercise, and Brokered Equity Financing

Completion will significantly reduce total indebtedness by $68 million, repositioning the Company to be 1.5x to 2.0x exit debt-to-EBITDA with estimated free funds flow of $17 million to $22 million in 2023 and further debt reductions targeted in 2024

New investment and brokered equity financing to fund immediate working capital needs and ongoing field operations

Strengthens financial profile on a pro-forma basis, relieving current financial hardship and allowing PPR to further de-risk its business through low-risk optimization program and drilling

CALGARY, Alberta, March 29, 2023 (GLOBE NEWSWIRE) -- Prairie Provident Resources Inc. ("Prairie Provident" or the "Company") is pleased to announce that it has entered into a Debt Restructuring Agreement (the "Debt Restructuring Agreement") with PCEP Canadian Holdco, LLC (the "Noteholder"), which holds all of the Company's outstanding subordinated notes (the "Subordinated Notes") and share purchase warrants, and certain affiliates of the Noteholder, and agreements with certain other parties, for various recapitalization transactions (collectively, the "Recapitalization") to, among other things, raise additional equity and debt capital, significantly reduce the Company's total debt through a repayment of all outstanding Subordinated Notes with equity, waive certain defaults under existing credit agreements, and extend the maturity date of its senior secured credit facility (the "First Lien Loan"). In connection with the Recapitalization, Prairie Provident has applied to the Toronto Stock Exchange ("TSX") for an exemption from shareholder approval requirements under TSX rules, pursuant to the 'financial hardship' provisions of the TSX Company Manual, as prompt action is required to relieve the Company's current financial difficulties and enable it to normalize operations and resume the development of its assets.

The Recapitalization includes the following principal transactions, all of which are subject to certain conditions as provided in the Debt Restructuring Agreement and other applicable transaction agreements:

an immediate new investment of US$3.64 million (approximately C$5 million at current exchange rates) by certain affiliates of the Noteholder through an issue of second lien notes due December 31, 2024 (the "Second Lien Notes"), which the Company expects to complete on or about March 30, 2023, and will provide the Company with the liquidity needed to meet immediate and pressing working capital requirements (the "Second Lien Financing");

amendments and waivers (the "First Lien Loan Amendments") to the First Lien Loan, under which total advances of US$19.1 million and C$41.1 million are currently drawn and outstanding, to extend the maturity date from December 31, 2023 to July 1, 2024, defer any borrowing base redetermination until 2024, provide additional covenant flexibility, and waive certain financial covenant and other defaults as more particularly described below, which amendments will become effective on completion of the Second Lien Financing and the concurrent effectiveness of the Subordinated Note Amendments described below;

amendments and waivers (the "Subordinated Note Amendments") to the Subordinated Notes to provide additional covenant flexibility, extend the maturity date of the Subordinated Notes currently due June 30, 2024 to December 31, 2024, and waive certain financial covenant and other defaults as more particularly described below, which amendments are required now in order to address current defaults and ongoing compliance pending completion of the Subordinated Notes Conversion (defined below), and will become effective on completion of the Second Lien Financing and the concurrent effectiveness of the First Lien Loan Amendments;

settlement of all outstanding indebtedness under the Subordinated Notes, in the aggregate amount of US$52.8 million, through an issue of common shares of the Company ("Common Shares"), conditional upon Prairie Provident completion of an offering of new equity for gross proceeds of at least C$4,000,000 (the "New Equity Condition"), at an agreed repayment price equal to 105% of the price at which equity is in fact sold in such offering (the "Subordinated Notes Conversion");

concurrently with the Subordinated Notes Conversion, exercise by the Noteholder, on a cashless basis, of the 34,292,360 warrants of the Company previously issued in December 2020 in connection with the Subordinated Note financing completed at that time, which warrants have an exercise price of C$0.0192 per share (the "Warrant Exercise"); and

a brokered 'best efforts' equity offering by the Company for minimum aggregate gross proceeds of C$4,000,000 of common shares and warrants (the "Equity Financing"), in reliance upon the 'listed issuer financing exemption' (LIFE) under applicable Canadian securities laws, successful completion of which will satisfy the New Equity Condition.

The First Lien Loan Amendments, the Subordinated Note Amendments and the Second Lien Financing are not conditional on completion of any other transactions forming part of the Recapitalization, but are conditional on one another and on the Company's agreement to immediately proceed with and pursue the remainder of the Recapitalization transactions on the terms summarized herein.

The Subordinated Notes Conversion is conditional on, among other things, satisfaction of the New Equity Condition not later than May 31, 2023 and all requisite TSX approvals, including acceptance of the Company's reliance on the financial hardship exemption described below for the completion of certain of the Recapitalization transactions.

The Recapitalization is necessary for the Company to relieve its current condition of financial hardship, resulting from an unsustainable total debt level and pressing liquidity deficit. It will achieve a significant deleveraging of Prairie Provident, reducing total debt by approximately 49% from approximately C$139 million1 to C$71 million2 after giving effect to the Second Lien Financing and Subordinated Notes Conversion. New capital from the Second Lien Financing (approximately C$5 million at current exchange rates) will bring immediate liquidity relief, with net proceeds directed towards outstanding payables of which approximately C$5 million are over 60 days past due. Payment delays have strained relationships with vendors and service providers, and the timely remedy of those delays is crucially important to normalize operations and resume development activity. Immediate capital through the Second Lien Financing, promptly followed by incremental near-term capital through the Equity Financing (minimum C$4 million in gross proceeds), will be used to retire overdue payables and regularize the Company's working capital position, which in turn provides Prairie Provident with the funds needed to meet its business objectives and liquidity requirements for the next 12 months.

Given the large number of Common Shares to be issued pursuant to the Recapitalization, the Company anticipates that it will seek approval at its next annual meeting of shareholders for a consolidation of its Common Shares. Whether the Company proceeds with a consolidation, and the consolidation ratio, will be determined in advance of the annual meeting.

Further details regarding the Recapitalization and constituent transactions, the terms of which have been negotiated at arm's length between the Company and the applicable counterparties, are provided below.

______________________
1 Comprised of C$41.1 in CAD advances under the First Lien Loan, US$19.1 million in USD advances under the First Lien Loan, and US$52.8 million in Subordinated Notes (including deferred interest amounts paid in kind), with USD amounts converted to CAD at an exchange rate of USD 1.00 to CAD 1.3626.

2 Comprised of C$41.1 in CAD advances under the First Lien Loan, US$19.1 million in USD advances under the First Lien Loan, and US$3.64 million in Second Lien Notes, with USD amounts converted to CAD at an exchange rate of USD 1.00 to CAD 1.3626.

Benefits to Prairie Provident

The Recapitalization will, if completed, significantly reduce the Company's total indebtedness, stop the accrual of additional indebtedness that has been accumulating since April 2020 as deferred interest amounts paid in kind on the Subordinated Notes (which amounts totaled US$3.3 million in 2022 alone), materially reduce the Company's foreign exchange exposure on USD denominated debt, provide comfort and stability with respect to the borrowing base and term of the First Lien Loan and covenant compliance thereunder, and better position the Company to execute on future opportunities. In the immediate term, the Second Lien Financing will provide the Company with the liquidity needed to meet immediate working capital requirements for ongoing field operations by significantly reducing overdue trade payables. Prompt completion of the Equity Financing will further improve the Company’s liquidity profile to a sustainable level, including to remain compliant with a C$500,000 minimum liquidity requirement under the First Lien Loan.

Going forward, completion of the Recapitalization is expected to provide Prairie Provident with a sustainable capital structure and the capital resources necessary to optimize its current producing assets as well as develop its currently undeveloped land base, for the benefit of all stakeholders. Significant improvements to the Company's overall leverage and non-cash interest burden is expected to allow Prairie Provident to direct more of its operating cash flow towards additional low-risk well reactivations, optimization and development drilling, and improve its ability to execute on future refinancing, acquisition and divestiture, and other transaction opportunities. Management believes that the rates of return offered by the Company's assets, with a 20.4-year reserve life index (based on proved plus probable reserves and current production levels) and significant tax pools in excess of C$800 million, support continued investment to create shareholder value.

Strategic Rationale for the Recapitalization

In recent years, Prairie Provident has faced an increasingly challenging lack of liquidity and deteriorating capital resource position. The Company is currently fully drawn on the First Lien Loan, with no further draws permitted. Absent the Recapitalization, its only source of capital is from internally generated funds from operations, and the First Lien Loan would mature on December 31, 2023.

The Company has over the past several months actively sought out and evaluated strategic alternatives intended to address its liquidity and capital resource constraints. The Recapitalization is the culmination of these efforts. In the meantime, Prairie Provident's debt levels have continued to grow as it is required to make all interest payments on its Subordinated Notes in kind. From an original principal amount of US$39.9 million, outstanding indebtedness under the Subordinated Notes has grown to approximately US$52.8 million as a result of deferred interest amounts that have been paid in kind.

The Company's leverage position has also driven lender requirements, pursuant to the terms of the First Lien Loan and Subordinated Notes, to hedge a significant portion of forecast production. Commodity price movements resulted in total realized hedging losses of approximately C$21.2 million in the first nine months of 2022, which impaired the Company's ability to benefit from improved commodity pricing during this period. This adverse cash flow impact, combined with higher royalty payments based on prevailing commodity prices and inflation in operating and capital costs, drove a significant deterioration in Prairie Provident's working capital position through 2022 and into 2023.

The Company's rising debt burden and working capital deficit has left it with an increasingly limited ability to invest in capital programs, stifling growth and the creation of shareholder value. Completion of the Recapitalization will enable the Company to reverse this trend by materially improving its balance sheet and providing financial flexibility to invest in future growth.

Equity Financing through LIFE Offering

In connection with the Equity Financing, the Company has entered into an agreement with Research Capital Corp., as sole agent and sole bookrunner (the "Agent"), for a best-efforts basis, private placement of equity units ("Units") at a price of C$0.10 per Unit for minimum aggregate gross proceeds of C$4,000,000. Each Unit will be comprised of (i) one Common Share, and (ii) one-half of one Common Share purchase warrant (each whole warrant, a "Warrant").

Each whole Warrant will entitle the holder thereof to subscribe for and purchase one Common Share at an exercise price of C$0.1265 for a period of 60 months from closing of the Equity Financing.

Matthew Shyba, currently one of Prairie Provident's largest shareholders and a director of the Company since July 2022, has provided an indication of interest for a lead order in the amount of $500,000 (12.5% of the minimum offering size). The Company welcomes Mr. Shyba’s continued support and his input into refocusing the business to enhance shareholder value, a key step of which is completing the Recapitalization.

The closing of the Equity Financing, which may occur in multiple tranches, is expected to occur on or about the week of April 13, 2023, or such later or earlier dates as the Agent and the Company may determine. Prairie Provident intends to close the Equity Financing as soon as possible in order to address its near-term working capital needs.

Completion of the Equity Financing is subject to completion of the Second Lien Financing (which is conditional on the First Lien Loan Amendments and Subordinated Note Amendments having become effective), and the concurrent completion of the Subordinated Notes Conversion and Warrant Exercise, and to Prairie Provident receiving all necessary TSX approvals.

The Equity Financing will be conducted on a prospectus-exempt basis pursuant to the 'listed issuer financing exemption' in Part 5A of National Instrument 45-106 – Prospectus Exemptions ("NI 45-106") (the "Listed Issuer Financing Exemption") to purchasers resident in Canada, except Québec, and/or other qualifying jurisdictions. Any Units issued and sold pursuant to the Listed Issuer Financing Exemption, and any Common Shares issued on a future exercise of Warrants, will not be subject to any restricted hold period pursuant to applicable Canadian securities laws. In addition, the Company will use commercially reasonable efforts to obtain the necessary approvals to list the Warrants on the TSX upon closing of the Equity Financing. Listing will be subject to the approval of the TSX in accordance with its original listing requirements.

In consideration for its services, the Agent will receive a cash commission equal to 8% of the gross proceeds of the Equity Financing plus broker warrants equal to 8% of the total number of Units sold (subject to a reduced 4% rate for sales to certain 'president's list' investors). Each broker warrant will entitle the holder to subscribe for and purchase one Unit at a price of $0.1265 for a period of 60 months after closing of the Equity Financing.

There is an offering document related to the Equity Financing that can be accessed under the Company's issuer profile at www.sedar.com and on the Company's website at www.ppr.ca. Prospective investors should read this offering document before making an investment decision.

This news release does not constitute an offer to sell or a solicitation of an offer to buy, nor shall there be any sale of, any securities in the United States or in any jurisdiction in which such offer, solicitation or sale would be unlawful. The securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the "1933 Act") or any U.S. state securities laws, and may not be offered or sold within the United States or to, or for account or benefit of, U.S. Persons (as defined in Regulation S under the 1933 Act) except in compliance with, or pursuant to an available exemption from, the registration requirements of the 1933 Act and applicable U.S. state securities laws.

First Lien Loan Amendments

The Company has entered into an amending agreement and waiver with the lenders under the First Lien Loan to extend the maturity date from December 31, 2023 to July 1, 2024, to defer any borrowing base redetermination until 2024, to reset financial covenants to thresholds that align with the Company's current expectations for the remaining term, and to waive certain defaults relating to non-compliance with specified hedging requirements, not having repaid amounts in excess of the maximum permitted amount of CAD denominated advances previously available under the First Lien Loan, and anticipated non-compliance with certain financial covenants as at December 31, 2022, as well as corresponding cross-defaults under the agreements governing the Subordinated Notes. Going forward, the Company will be required to maintain available cash and cash equivalents of at least C$500,000 at all times. The First Lien Loan Amendments also provide for additional reporting obligations in favour of the lenders, and remove certain procedural requirements pertaining to any future exercise of lender remedies.

The First Lien Loan Amendments will become effective on completion of the Second Lien Financing and the concurrent effectiveness of the Subordinated Note Amendments, and are not otherwise conditional upon completion of any other transaction forming part of the Recapitalization.

Prairie Provident currently has approximately US$19.1 million and C$41.1 million drawn on the First Lien Loan. No further draws are permitted. The interest margin on the First Lien Loan is unchanged at 950 bps per annum above benchmark rates.

Failure to complete the Equity Financing and the Subordinated Debt Conversion by May 31, 2023 will constitute an event of default under the First Lien Loan, in which case the lenders under the First Lien Loan would be entitled to demand repayment of the full amounts owing under the First Lien Loan and exercise creditors' remedies against the Company. Prairie Provident's liquidity requirements are, however, such that completion of the Recapitalization cannot be delayed until May.

Subordinated Note Amendments

The Company has concurrently entered into amending agreements and waivers with the Noteholder to extend the maturity date of the Subordinated Notes maturing on June 30, 2024 to December 31, 2024, to change the maturity date of the Subordinated Notes maturing on December 21, 2026 to December 31, 2024, to reset financial covenants to thresholds that align with the Company's current expectations for the remaining term, and to waive non-compliance with specified hedging requirements and anticipated non-compliance with certain financial covenants as at December 31, 2022, as well as corresponding cross-defaults under the agreement governing the First Lien Loan.

The Subordinated Note Amendments will become effective on completion of the Second Lien Financing and the concurrent effectiveness of the First Lien Loan Amendments, and are not otherwise conditional upon completion of any other transaction forming part of the Recapitalization.

Prairie Provident currently has approximately US$52.8 million in outstanding indebtedness under the Subordinated Notes, including US$12.9 million of Subordinated Notes representing deferred interest amounts that have been paid in kind. The interest margin on the Subordinated Notes is unchanged at 8.0% for the Subordinated Notes issued on each of October 31, 2017 and November 21, 2018, and 12.0% for the Subordinated Notes issued on December 31, 2020.

Failure to complete the Equity Financing and the Subordinated Notes Conversion by May 31, 2023 will constitute an event of default under the Subordinated Notes and a termination of the waivers described herein. Prairie Provident's liquidity requirements are, however, such that completion of the Recapitalization cannot be delayed until May.

Second Lien Financing and Subordinated Notes Conversion

Prairie Provident has entered into the Debt Restructuring Agreement with the Noteholder and certain of its affiliates providing for both the Second Lien Financing and the Subordinated Notes Conversion and Warrant Exercise.

Second Lien Financing

In accordance with terms and conditions of the Debt Restructuring Agreement, Prairie Provident and certain affiliates of the Noteholder have agreed to enter into a note purchase agreement for the Second Lien Financing, pursuant to which such affiliates will purchase US$3.64 million (approximately C$5 million at current exchange rates) principal amount of new Second Lien Notes.

The Second Lien Notes will have a maturity date of December 31, 2024 and bear interest at a margin equal to 1150 bps per annum above the Secured Overnight Financing Rate (SOFR). Interest due on the Second Lien Notes must be paid in kind while the First Lien Loan is outstanding.

The note purchase agreement for the Second Lien Notes also provides for payment by the Company of a deferred compensation fee on the later of (i) maturity or earlier prepayment or acceleration of the Second Lien Notes, and (ii) the date on which the First Lien Loan is fully repaid, in an amount equal to US$2.91 million less actual interest and breakage cost obligations paid on the Second Lien Notes from the issue date through such later date, provided that such fee shall not result in an internal rate of return on the Second Lien Notes that exceeds 45% per annum. Assuming (i) an issue date of March 30, 2023, (ii) repayment at maturity on December 31, 2024, and (iii) that SOFR remains at 4.81% through the term, total accrued interest on the Second Lien Notes will be approximately US$1.04 million and the deferred compensation fee payable on maturity will therefore be US$1.87 million.

The Company expects to complete the Second Lien Financing on or about March 30, 2023.

Completion of the Second Lien Financing will happen concurrently with the First Lien Loan Amendments and Subordinated Note Amendments becoming effective, and is not otherwise conditional upon completion of any other transaction forming part of the Recapitalization.

Failure to complete the Equity Financing and the Subordinated Notes Conversion by May 31, 2023 will constitute an event of default under the Second Lien Notes.

Subordinated Notes Conversion

Pursuant to the Debt Restructuring Agreement, Prairie Provident and the Noteholder have also agreed, upon and subject to the terms and conditions thereof, including the New Equity Condition, TSX approval (including acceptance of the Company's reliance on the financial hardship exemption described below) and other customary conditions, to effect the Subordinated Notes Conversion.

The Subordinated Notes Conversion will settle all outstanding indebtedness under the Subordinated Notes, in the aggregate original principal amount of US$39.9 million plus approximately US$12.9 million in deferred interest amounts previously paid in kind, through an issue of Common Shares at an agreed repayment price equal to 105% of the price at which Common Shares (or units comprised of Common Shares and warrants) are issued under the financing transaction that meets the New Equity Condition.

Assuming satisfaction of the New Equity Condition through the Equity Financing, and based on the Unit offering price thereunder, the repayment price applicable to the Subordinated Notes Conversion will be C$0.105 per share. At that conversion price, and applying a current USD-to-CAD exchange rate of 1.3626 to the approximately US$52.8 million total balance currently outstanding under the Subordinated Notes, approximately 686 million Common Shares will be issuable pursuant to the Subordinated Notes Conversion. The actual exchange rate that will be applied on the Subordinated Notes Conversion will be the rate quoted by the Bank of Canada on the day before the date on which Subordinated Notes Conversion is completed. The number of Common Shares ultimately issuable on completion of the Subordinated Notes Conversion will therefore depend on the exchange rate at the time of completion as well as the actual outstanding balance owed under the Subordinated Notes at that time, which based on interest rates currently applicable to the Subordinated Notes increases by approximately US$13,000 per day.

The Warrant Exercise will be effected concurrently with the Subordinated Notes Conversion, whereby the approximately 34.3 million outstanding warrants originally issued by Prairie Provident in connection with Subordinated Note transactions previously completed in December 2020 will be exercised on a cashless basis. Based on an assumed market price per Common Share of C$0.1265 and the exercise price of C$0.0192 per share under the warrants, approximately 29.1 million additional Common Shares will be issued on the Warrant Exercise.

The Common Shares issued pursuant to the Subordinated Notes Conversion will be subject to a 4-month restricted hold period under applicable Canadian securities laws. The Common Shares issued pursuant to the Warrant Exercise will not be subject to a 4-month restricted hold period under applicable Canadian securities laws. All such Common Shares will, however, be subject to selling restrictions applicable to 'control persons' under the applicable Canadian securities laws, as the Noteholder will be a 'control person' of Prairie Provident within the meaning of such laws.

In addition, the Noteholder has agreed with the Company to certain 'lock-up' restrictions pursuant to which the Noteholder will not, without Prairie Provident's consent, dispose of Common Shares acquired by it pursuant to the Subordinated Notes Conversion, otherwise than in connection with a business combination, a reorganization or restructuring, or an acquisition of all or substantially all of the Common Shares, or pursuant to a private sale, or to an affiliate or other related party. The lock-up restrictions will cease to apply as to 33?% all such Common Shares on each of the 6-month, 12-month and 18-month anniversaries, respectively, of the Subordinated Notes Conversion.

The total pro forma holding of Common Shares (undiluted) of the Noteholder following completion of the Equity Financing for minimum gross proceeds of C$4,000,000 and following the Subordinated Notes Conversion and related Warrant Exercise is expected to be approximately 715 million Common Shares, representing approximately 81% of the total outstanding Common Shares.

As the Noteholder will, after giving effect to the Subordinated Notes Conversion, Warrant Exercise and Equity Financing, hold more than 80% of the outstanding Common Shares after the Recapitalization, the Noteholder will be a 'control person' of Prairie Provident under applicable Canadian securities laws, and the Recapitalization will materially affect control of Prairie Provident within the meaning of TSX rules. See "Pro Forma Shareholding Information" below.

Investor Rights Agreement

The Debt Restructuring Agreement also provides that in connection with completion of the Subordinated Notes Conversion the Company will enter into an Investor Rights Agreement and a Registration Rights Agreement with the Noteholder and certain of its affiliates (the "Holders" for the purposes of the following).

Pursuant to the Investor Rights Agreement:

the size of the Company's board of directors will be fixed at five (5), with the Holders having the right to nominate three directors for so long as they hold more than 50% of the outstanding voting securities of the Company, two directors for so long as they hold at least 25% of the outstanding voting securities but less than 50%, and one director for so long as they hold at least 10% of the outstanding voting securities but less than 25%;

the Holders will have pre-emptive rights to participate in any future public or private offering by the Company of equity securities, or of securities that are convertible or exercisable into equity securities, to such extent as maintains their proportionate interest in voting securities of the Company; and

the Holders will, with respect to the Common Shares issued on the Subordinated Notes Conversion, receive an anti-dilution adjustment right (the "Adjustment Right") entitling the Holders to receive, for no additional consideration and subject to certain exceptions, in the event of Prairie Provident issuing, within 6 months after completion of the Subordinated Notes Conversion, Common Shares a price (or securities convertible or exercisable into Common Shares at a conversion or exercise price) that is less than the repayment price per share at which the Subordinated Notes Conversion is completed, such number of additional Common Shares as (i) reduces the effective price per share of the Common Shares issued on the Subordinated Notes Conversion, when taken together with such additional Common Shares issued for no additional consideration, to such lower price, or (ii) maintains the Holders' voting interest, whichever number is the lesser. As an illustrative example, assuming an issue to the Noteholder of 686 million Common Shares pursuant to the Subordinated Note Conversion (as set out under "Pro Forma Shareholding Information" below) at a repayment price of C$0.105, and a subsequent issue of 50 million Common Shares at a price of C$0.08 per share one month thereafter, the Adjustment Right could result in a maximum of up to 210 million additional Common Shares being issued to the Holders for no additional consideration, such that the average price per share of the 896 million Common Shares issued pursuant to the Subordinated Note Conversion plus the additional Common Shares issued pursuant to the Adjustment Right becomes C$0.08 – except that the number of such additional Common Shares cannot exceed the number that would simply maintain the Holders' voting interest. This latter cap operates to prevent a small issuance of Common Shares at a price below the repayment price from resulting in a disproportionately large number of additional Common Shares being issued pursuant to the Adjustment Right.

Registration Rights Agreement

The Registration Rights Agreement will give the Holders customary rights to require that Prairie Provident file a prospectus and otherwise take steps to qualify for public distribution a future sale of Common Shares by the Holders (i.e., demand registration rights), and include in a future public offering of equity securities that might be undertaken by the Company, in addition to the new securities offered by the Company, shares of the Holders (i.e., piggy-back registration rights), all upon and subject to the terms and conditions of the Registration Rights Agreement.

Pro Forma Shareholding Information

The following table sets forth information regarding the total pro forma holdings of Common Shares (undiluted) of the Noteholder, of subscribers under the Equity Financing, and of current Prairie Provident shareholders, after completion of the Subordinated Notes Conversion, the Warrant Exercise and the Equity Financing, based on the assumptions identified therein and in the notes to the table.

	Assuming Minimum Gross Proceeds of C$4,000,000 under Equity Financing (1)	Assuming Maximum Gross Proceeds of C$4,075,000 under Equity Financing (2)
Noteholder per Subordinated Notes Conversion (3)	77.5% (686 million Common Shares)	77.4% (686 million Common Shares)
Noteholder per Warrant Exercise (4)	3.3% (29 million Common Shares)	3.3% (29 million Common Shares)
Noteholder Subtotal	80.8% (715 million Common Shares)	80.7% (715 million Common Shares)
Subscribers under Equity Financing	4.5% (1) (40 million Common Shares)	4.6% (2) (41 million Common Shares)
TOTAL NEW SHARES (Subordinated Notes Conversion plus Warrant Exercise plus Equity Financing)	85.3% (5) (755 million Common Shares)	85.3% (6) (755 million Common Shares)
EXISTING SHAREHOLDERS	14.7% (130 million Common Shares)	14.7% (130 million Common Shares)

Figures may not add due to rounding.

Notes:

(1)	Assumes the issuance of 40.0 million Units at a price of C$0.10 per Unit (being a 20.9% discount to the market price of the Common Shares on the TSX on March 28, 2023 of C$0.1265 per share) for total gross proceeds of C$4.0 million.

(2)	Assumes the issuance of 40.75 million Units at a price of C$0.10 per Unit for total gross proceeds of C$4.1 million.

(3)	Assumes (i) a repayment price of C$0.105 per share, (ii) a completion date of April 1, 2023, at which time the outstanding balance owed under the Subordinated Notes will be US$52.8 million and (iii) a USD-to-CAD exchange rate of 1.3626.

(4)	Assumes a market price of the Common Shares on the TSX of C$0.1265 per share at the date of completion, which would result in an 'in-the-money' amount of C$0.1073 per warrant held by the Noteholder based on the exercise price of C$0.0192 per share, with the total number of Common Shares issuable pursuant to the Warrant Exercise being such number of Common Shares as have a value, based on such market price, equal to the aggregate in-the-money value of all such warrants.

(5)	Represents an increase of 755 million or approximately 680% in the number of Common Shares outstanding, from 130 million Common Shares outstanding today to 885 million outstanding after completion of the Subordinated Notes Conversion, Warrant Exercise and Equity Financing based on the assumptions described above.

(6)	Represents an increase of 755 million or approximately 681% in the number of Common Shares outstanding, from 130 million Common Shares outstanding today to 885 million outstanding after completion of the Subordinated Notes Conversion, Warrant Exercise and Equity Financing based on the assumptions described above.

Background to and Consideration of the Recapitalization Transactions

Prairie Provident has limited liquidity and capital resources from which to meet its obligations and execute on its business plan. Available borrowing capacity under the First Lien Loan of US$6.4 million at year-end 2021 decreased to nil at year-end 2022, partly due to a year-over-year reduction in the borrowing base from US$53.8 million to US$50 million. Deferred interest amounts on the Subordinated Notes have, in accordance with commitments to the lenders under the First Lien Loan, continued to be paid-in-kind and increase total indebtedness under the Subordinated Notes.

The Company's liquidity has been further compromised by the adverse cash flow impact of low commodity price hedges throughout 2022, which when combined with increasing royalty payments and inflation in operating and capital costs resulted in Prairie Provident benefiting much less from higher commodity prices in 2022 than many of its peers and contributed to a current working capital deficit that is unsustainable. Without access to further draws under the First Lien Loan, the Company has an immediate need for new capital from which to satisfy payables and continue to fund operations.

The combination of high debt and low liquidity has limited the Company's ability to execute on its business plan and access new capital (equity, debt or other), or to generate additional funds through assets sales, joint ventures or other industry transactions on reasonable terms.

Given the December 31, 2023 maturity of the First Lien Loan and its over-levered balance sheet, the Company engaged independent financial advisors in mid-2022 to assist in identifying and developing potential refinancing and/or disposition opportunities, while also pursuing discussions with the First Lien Loan lenders and the holders of the Subordinated Notes, to explore potential solutions to its liquidity and capital resources position and avoid an event of default or similarly adverse consequences under its existing credit arrangements. Following a broad canvass to surface potential alternatives, the Company's efforts have culminated in the Recapitalization.

In considering the Recapitalization and the terms and conditions of each of its transactions, the Prairie Provident board of directors (the "Board of Directors") undertook a review of the Company's reasonable alternatives, prospects and the Company's borrowing arrangements, including the consideration of the factors and matters set forth below:

the absence of other alternatives reasonably available to Prairie Provident to refinance (by way of debt, equity or otherwise) its current borrowing arrangements;

the immediacy and magnitude of the Company's working capital requirements for ongoing field operations and to settle outstanding payables, with a significant portion of the Company’s trade payables substantially overdue;

the certainty of a substantial reduction of debt and related servicing costs through the Subordinated Debt Conversion, and the overall reduction of total debt upon completion of the Recapitalization from approximately C$139 million to approximately C$71 million, a decrease of approximately 49%;

the mitigation of solvency risk associated with the Company's status quo position, including the risk of near immediate debt maturities, and potential creditor or similar proceedings in connection to the same, which may have the effect of reducing or eliminating any value associated with Prairie Provident's equity;

the anticipated ability to apply a portion of cash flow in 2023 to repay some portion of outstanding amounts under the First Lien Loan, further de-leveraging the Company's balance sheet and providing potential liquidity to resume drilling and development opportunities;

the repayment price per share under the Subordinated Notes Conversion;

that the Subordinated Notes Conversion preserves the Company's cash resources, which may be used for other expenditures, including development of the Company's asset base and repayment of outstanding amounts under the First Lien Loan;

that since April 2020, all interest under the Subordinated Notes, which currently bear interest at 8% to 12% per annum, has been paid in kind and as such capitalized as additional principal amount of Subordinated Notes, which has a compounding effect to increase the principal amount payable thereunder from time to time;

the advantages of having potential funding available to resume development of the Company's asset base, with a view to increasing production, reserves and revenue generating activities for the benefit of all stakeholders; and

the risks associated with trying to secure funding from other third parties, including the risk that such funding may not be available, on any reasonable terms, measured against the relative certainty of the Recapitalization.

No director has any interest in any Recapitalization transaction apart from Matthew Shyba, who as noted above has provided an indication of interest for a lead order in the amount of $400,000 under the Equity Financing. That potential interest was recognized and considered by the Independent Committee referred to below.

Post-Recapitalization Outlook

The Company believes that the Recapitalization will allow it to begin to reinvest cash flows in its core operations. Production averaged 4,072 boe/d in 2022, with a decline in the fourth quarter due to the Company’s lack of capital. If the Recapitalization is completed, Prairie Provident believes that it will be able to flatten out its production declines with a limited capital budget in 2023, while returning to growth in 2024. Based on the Sproule December 31, 2022 price deck, the Company's guidance for key financial figures would be as follows:

	2023	2024
Avg. Production (boe/d)	4,000 - 4,200	4,300 - 4,500
Capital Budget (1)	$14 - 16MM	$22 - 25MM
EBITDA (2)	$35 - 42MM	$40 - 45MM
Free Funds Flow (2)	$17 - 22MM	$20 - 25MM
Exit Debt	$55 - 65MM	$45 - 55MM
Exit Debt/EBITDA	1.5 - 2.0x	1.2 - 1.7x

Notes:

(1)	Including expenditures on Asset Retirement Obligations.

(2)	EBITDA is a non-GAAP measure. See "Non-GAAP and Other Financial Measures, and Oil and Gas Metrics" below in this news release.

(3)	Free Funds Flow is a non-GAAP measure. See "Non-GAAP and Other Financial Measures, and Oil and Gas Metrics" below in this news release.

TSX Approval and Financial Hardship Exemptions

Completion of the Recapitalization, and in particular the Subordinated Notes Conversion, the Equity Financing (including insider participation in such financing) and the Adjustment Right under the proposed Investor Rights Agreement, is conditional on receipt by Prairie Provident of TSX approvals.

Pursuant to TSX rules, the Recapitalization would ordinarily require approval of the Company's disinterested shareholders:

under section 604(a)(i) of the TSX Company Manual, on the basis that the Noteholder will, after giving effect to the Subordinated Notes Conversion and related Warrant Exercise as well as the Equity Financing, hold more than 20% of the outstanding Common Shares and the Recapitalization will therefore be considered by TSX to materially affect control of Prairie Provident;

under section 604(a)(ii) of the TSX Company Manual, on the basis that (i) the Noteholder is, by reason of holding warrants pursuant to which it has the right to acquire more than 10% of the outstanding Common Shares, an insider of Prairie Provident, and (ii) the Common Shares issuable to the Noteholder on the Subordinated Notes Conversion and Warrant Exercise, and the total interest plus deferred compensation fee payable over the term of the Second Lien Notes payable to certain affiliates of the Noteholder, will provide the Noteholder and such affiliates with more than 10% of the Company's market capitalization;

under section 607(g)(i) of the TSX Company Manual, on the basis that (i) the repayment price under the Subordinated Notes Conversion (anticipated to be C$0.105 per Common Share based on the offering price of C$0.10 per Unit under the Equity Financing) will be less than the 5-day volume weighted average trading price of the Common Shares prior to the date of this news release (C$0.1265 per share), and (ii) the number of new Common Shares issuable pursuant to the Subordinated Notes Conversion (estimated to be approximately 686 million Common Shares based on the assumptions described above under "Pro Forma Shareholding Information") will be greater than 25% of the number of Common Shares currently issued and outstanding on an undiluted basis (130 million);

under section 607(g)(i) of the TSX Company Manual, on the basis that (i) the offering price under the Equity Financing (C$0.10 per Unit) is less than the 5-day volume weighted average trading price of the Common Shares prior to the date of this news release (C$0.1265 per share), and (ii) the number of new Common Shares issuable pursuant to the Equity Financing (being at least 40 million Common Shares forming part of the minimum number of Units issuable to raise gross proceeds of not less than C$4,000,000 plus a further 20 million Common Shares issuable on exercise of the warrants forming part of such Units) will be greater than 25% of the number of Common Shares currently issued and outstanding on an undiluted basis (130,116,666);

under section 607(g)(ii) of the TSX Company Manual, on the basis that (i) the Noteholder is, by reason of holding warrants pursuant to which it has the right to acquire more than 10% of the outstanding Common Shares, an insider of Prairie Provident, and (ii) the total number of Common Shares issuable to the Noteholder on the Subordinated Notes Conversion and Warrant Exercise, whether alone or taken together with any number of Common Shares (including Common Shares issuable under the warrants) that any director or officer of the Company may acquire under the Equity Financing, is greater than 10% of the outstanding Common Shares (it being noted, however, that no director or officer that acquires Common Shares, including Common Shares issuable under the warrants, will individually acquire more than 10% of the outstanding Common Shares);

under section 607(g)(ii) of the TSX Company Manual, on the basis that Matthew Shyba, a current director of Prairie Provident who has provided an indication of interest for a lead order of $500,000 under the Equity Financing might, and any other director or officer of the Company that participates in the Equity Financing might, depending on overall market demand, acquire under the Equity Financing such number of Common Shares (including Common Shares issuable under the warrants) as exceeds 10% of the number of Common Shares currently outstanding;

under section 607(e) of the TSX Company Manual, on the basis that the Adjustment Right constitutes an adjustment for which not all shareholders are compensated, and may result in securities being issued at a price lower than market price less the permissible discount under TSX rules;

on the basis that the price at which Common Shares are issuable pursuant to the Subordinated Notes Conversion, and the price at which Units are offered pursuant to the Equity Financing, was determined prior to the pending release of Prairie Provident's financial and operating results for the year-ended December 31, 2022, which release is expected to be made on March 31, 2023;

on the basis that the compensation payable to the Agent for their services in respect of the Equity Financing is higher than general TSX guidelines; and

on the basis that (i) the repayment price for the Subordinated Note Conversion and offering price under the Equity Financing were determined prior to public disclosure of the Recapitalization, (ii) TSX would ordinarily in such circumstances restrict insider participation to maintenance of their pro rata holding, unless otherwise approved by shareholders, and (iii) participation by the Noteholder (who is, as a result of holding warrants, an insider of the Company) in the Recapitalization will, and participation by any director or officer in the Equity Financing may, result in such parties increasing their pro rata holdings of Common Shares.

The Company has applied to the TSX pursuant to the "financial hardship" provisions of section 604(e) of the TSX Company Manual for an exemption from any such shareholder approval requirement, on the basis that Prairie Provident is in serious financial difficulty and the immediacy of its need to reduce indebtedness and raise additional capital does not afford it sufficient time to seek that approval. This is reflected in the Debt Restructuring Agreement entered into between the Noteholder and Prairie Provident in respect of the Recapitalization, which (i) provides for both the Second Lien Financing and Subordinated Notes Conversion, (ii) contemplates immediate action on the Recapitalization, and (iii) includes as a condition precedent to the Noteholder's obligation to complete the Subordinated Notes Conversion that the TSX accept the Company's application to rely on the financial hardship exemption. This aligns with the Company's pressing need for debt reduction and liquidity relief.

As the offering price under the Equity Financing (and therefore the repayment price under the Subordinated Notes Conversion) was determined before the Recapitalization was disclosed, the Company has also certified to the TSX that the Company would not have entered into the Recapitalization without having also priced the Equity Financing.

The TSX is considering the application in connection with its review of the Company's request for TSX approval of the applicable Recapitalization transactions. There is no certainty that the TSX will approve the Subordinated Notes Conversion, the Equity Financing (or the insider participation thereunder) or the Adjustment Right under the proposed Investor Rights Agreement, or accept the Company's application to rely on the financial hardship exemption.

A special committee of independent and disinterested directors (the "Independent Committee") has considered the terms of the Recapitalization transactions and, in the circumstances, recommended that the "financial hardship" application be made to the TSX. The Independent Committee has determined, and the Board of Directors has unanimously agreed, that Prairie Provident is in serious financial difficulty, and that the Recapitalization (including, in particular, the Subordinated Notes Conversion and Equity Financing) is reasonable in the circumstances and designed to improve the Company's financial situation. In doing so, the Independent Committee specifically considered the need for a timely completion of the Recapitalization in light of the Company's pressing financial obligations and the requirements of its lenders.

Prairie Provident expects that, as a consequence of its "financial hardship" exemption application, the TSX will place the Company under a remedial delisting review, which is normal practice when a listed issuer seeks to rely on this exemption. Although the Company believes that it will be in compliance with all continued listing requirements of the TSX upon conclusion of a delisting review, no assurance can be provided as to the outcome of that review and, therefore, on Prairie Provident's continued qualification for listing on the TSX.

The Company has determined that the Subordinated Notes Conversion (in the event that the Noteholder might be considered a 'related party' of Prairie Provident despite being a bona fide lender), and any participation by directors or officers in the Equity Financing, insofar as such transactions might be considered 'related party transactions' within the meaning of Multilateral Instrument 61-101 - Protection of Minority Security Holders in Special Transactions ("MI 61-101"), are also exempt from any formal valuation and minority approval requirements that might otherwise be applicable under MI 61-101 pursuant to the 'financial hardship' exemptions set forth in Sections 5.5(g) and 5.7(1)(e) of MI 61-101. In connection with the same, and as noted above, the Board of Directors (including all independent directors) has in good faith determined that: (i) the Company is in serious financial difficulty; (ii) the Subordinated Notes Conversion and the Equity Financing are designed to improve the financial position of the Company; and (iii) the terms of the Subordinated Notes Conversion and the Equity Financing are reasonable in the circumstances of the Company. Further information required by MI 61-101 in connection with the Subordinated Notes Conversion and the Equity Financing will be set forth in the Company's material change report to be filed under the Company's issuer profile on SEDAR at www.sedar.com if and as required by MI 61-101. The material change report will likely be filed less than 21 days before the closing of the Subordinated Notes Conversion and the Equity Financing, as Prairie Provident and other parties involved aim to complete the Recapitalization as soon as possible in order to address the Company's liquidity needs and debt burden.

ABOUT PRAIRIE PROVIDENT

Prairie Provident is a Calgary-based company engaged in the exploration and development of oil and natural gas properties in Alberta. The Company's strategy is to optimize our existing assets to provide stable low decline cash flow, and use those funds to improve the balance sheet and manage liabilities.

For further information, please contact:

Prairie Provident Resources Inc.

Patrick R. McDonald
Adam Smith
Tel: (403) 292-8150
Email: investor@ppr.ca

CAUTIONARY STATEMENTS:

Forward-Looking Statements

This news release contains certain statements (“forward-looking statements”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future performance, events or circumstances, are based upon internal assumptions, plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “believe”, “expect”, “intend”, “plan”, “budget”, “forecast”, “target”, “estimate”, “propose”, “potential”, “project”, “continue”, “may”, “will”, “should” or similar words suggesting future outcomes or events or statements regarding an outlook.

Without limiting the foregoing, this news release contains forward-looking statements pertaining to: completion of the Recapitalization and its expected effect on the Company's financial position; the sustainability of the Company's capital structure after giving effect to the Recapitalization; a prospective share consolidation for consideration by shareholders at the next shareholders' meeting; and future transaction opportunities; the Company's ability to flatten out its production declines; and projections as to average production, capital expenditure levels, EBITDA and free funds flow for 2023 and 2024, and exit debt and debt-to-EBITDA ratio for year-end 2023 and 2024.

Forward-looking statements are based on a number of material factors, expectations or assumptions of Prairie Provident which have been used to develop such statements but which may prove to be incorrect. Although the Company believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements, which are inherently uncertain and depend upon the accuracy of such expectations and assumptions. Prairie Provident can give no assurance that the forward-looking statements contained herein will prove to be correct or that the expectations and assumptions upon which they are based will occur or be realized. In particular, the Company can give no assurance that requisite TSX approvals for the Recapitalization will be received, or that the Recapitalization will be successfully completed. Actual results or events will differ, and the differences may be material and adverse to the Company. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the likelihood of the Company being able to raise the new equity capital necessary to satisfy the New Equity Condition, whether through the Equity Financing or another transaction; that the Second Lien Financing will be completed on March 30, 2023 as scheduled; the results from reactivation projects, that Prairie Provident will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities, and their consistency with past operations; the quality of the reservoirs in which Prairie Provident operates and continued performance from existing wells (including with respect to production profile, decline rate and product type mix); the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Prairie Provident’s reserves volumes; future commodity prices; future operating and other costs; future USD/CAD exchange rates; future interest rates; continued availability of external financing (including borrowing capacity under available credit facilities) and cash flow to fund Prairie Provident’s current and future plans and expenditures, with external financing on acceptable terms; the impact of competition; the general stability of the economic and political environment in which Prairie Provident operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Prairie Provident to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Prairie Provident has an interest in to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Prairie Provident to secure adequate product transportation; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Prairie Provident operates; and the ability of Prairie Provident to successfully market its oil and natural gas products.

The forward-looking statements included in this news release are not guarantees of future performance or promises of future outcomes, and should not be relied upon. Such statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements including, without limitation: reduced access to financing; higher interest costs or other restrictive terms of financing; changes in realized commodity prices; changes in the demand for or supply of Prairie Provident’s products; the early stage of development of some of the evaluated areas and zones; the potential for variation in the quality of the geologic formations targeted by Prairie Provident’s operations; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Prairie Provident or by third party operators; increased debt levels or debt service costs; inaccurate estimation of Prairie Provident’s oil and gas reserves volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and such other risks as may be detailed from time-to-time in Prairie Provident’s public disclosure documents (including, without limitation, those risks identified in this news release and Prairie Provident’s current Annual Information Form as filed with Canadian securities regulators and available from the SEDAR website (www.sedar.com) under Prairie Provident’s issuer profile).

The forward-looking statements contained in this news release speak only as of the date of this news release, and Prairie Provident assumes no obligation to publicly update or revise them to reflect new events or circumstances, or otherwise, except as may be required pursuant to applicable laws. All forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Barrels of Oil Equivalent

The oil and gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead nor at the plant gate, which is where Prairie Provident sells its production volumes. Boes may therefore be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency ratio of 6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of value.

Non-GAAP and Other Financial Measures, and Oil and Gas Metrics

This news release discloses certain financial measures that are 'non-GAAP financial measures' or 'supplementary financial measures' within the meaning of applicable Canadian securities laws. Such measures do not have a standardized or prescribed meaning under International Financial Reporting Standards (IFRS) and, accordingly, may not be comparable to similar financial measures disclosed by other issuers. Non-GAAP and other financial measures are provided as supplementary information by which readers may wish to consider the Company's performance but should not be relied upon for comparative or investment purposes. Readers must not consider non-GAAP and other financial measures in isolation or as a substitute for analysis of the Company’s financial results as reported under IFRS.

This news release also includes reference to certain metrics commonly used in the oil and gas industry but which do not have a standardized or prescribed meanings under the Canadian Oil and Gas Evaluation (COGE) Handbook or applicable law. Such metrics are similarly provided as supplementary information by which readers may wish to consider the Company's performance but should not be relied upon for comparative or investment purposes.

Following is additional information on non-GAAP and other financial measures and oil and gas metrics used in this news release.

EBITDA – EBITDA is a non-GAAP financial measure calculated as net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization. Management uses the EBITDA as a measure of operational performance and cash flow generating capability.

Free Funds Flow – Free funds flow is derived from adjusted funds flow, both of which are non-GAAP financial measures. Prairie Provident defines “adjusted funds flow” as cash flow from operating activities before the effects of decommissioning expenditures and changes in non-cash operating working capital, and excluding transaction costs, restructuring costs and other non-recurring items. The Company eliminates settlements of decommissioning expenditures from cash flow from operating activities as the amounts can be discretionary and may vary from period to period depending on its capital programs and the maturity of its operating areas. The settlement of decommissioning expenditures is managed within the capital budgeting process, which considers available adjusted funds flow. Changes in non-cash operating working capital are eliminated in the determination of adjusted funds flow as the timing of collection and payment are variable and by excluding them from the calculation, the Company believes that it is able to provide a more meaningful measure of its operations and ability to generate cash on a continuing basis. Management uses this measure to assess the Company's ability to finance capital expenditures, settle decommissioning obligations and repay debt. Prairie Provident defines “free funds flow” as adjusted funds flow less capital expenditures. Management believes that free funds flow provides a useful measure of the Company's ability to generate shareholder value.

Reserve Life Index – Reserve life index (RLI) is an oil and gas metric calculated by dividing total company share reserves by annualized production. RLI provides a summary measure of the relative magnitude of the Company's reserves through an indication as to how long they would last based on a current, annualized production rate and assuming no additions to reserves.

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From: LoneClone	4/5/2023 12:46:56 PM
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Gran Tierra Energy Provides Operational and Financial Update ca.finance.yahoo.com Gran Tierra Energy Inc. Tue, April 4, 2023 at 2:05 p.m. PDT·10 min read *Achieved First Quarter 2023 Total Company Average Production of Approximately 31,700 BOPD, an Increase of 8% from First Quarter 2022* *Acordionero Field Producing Approximately 20,000 BOPD for First Time Since Second Quarter 2019* *Share Buybacks: Purchased 13 Million Gran Tierra Shares of Common Stock During First Quarter 2023* *Bond Buybacks: Purchased $8 Million in Face Value of Gran Tierra 2025 Bonds During First Quarter 2023* CALGARY, Alberta, April 04, 2023 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE)(TSX:GTE)(LSE:GTE) today announced an operational and financial update. All dollar amounts are in United States dollars, and production amounts are on an average working interest before royalties (“WI”) basis unless otherwise indicated. Per barrel (“bbl”) and bbl of oil per day (“BOPD”) amounts are based on WI sales before royalties. Message to Shareholders Commenting on the Company’s ongoing successful drilling campaign and share and bond buyback programs, Gary Guidry, President and Chief Executive Officer of Gran Tierra, stated: "We are very pleased with the results so far from our 2023 development drilling campaign, which have demonstrated the quality of our assets and our ability to execute on our strategy. We plan to continue the development program until the end of second quarter 2023, with our high-impact exploration drilling campaign scheduled to commence early in third quarter 2023. We are also pleased with the resumption of both our share and bond buyback programs, which reflect our commitment to returning value to our shareholders and strengthening our balance sheet." Operations Update: Production During first quarter 2023 (the “Quarter”), Gran Tierra’s total average production was approximately 31,700 BOPD. Gran Tierra's total current average production1 for second quarter 2023 to date is approximately 33,700 BOPD, which is at the high end of the Company’s 2023 previously disclosed average annual production guidance. During second quarter 2023 to date, Acordionero’s current average production1 is approximately 20,000 BOPD, which is the first time this level of production has been reached since second quarter 2019 and is a result of the Company’s ongoing successful development drilling and asset management efforts through waterflooding to enhance oil recovery. Development During the Quarter the Company drilled 14 wells: Acordionero: 8 wells were drilled; 5 are on production, 2 are on water injection and 1 producer is being completed Costayaco: 4 wells were drilled; 2 producers are scheduled for completion and tie-in before the end of April 2023 and 2 water injection wells are completed and expected to begin injection during second quarter 2023 Moqueta: 2 wells were drilled; 1 is on production, and production casing is being run on the second one Production in the Suroriente Block averaged approximately 8,167 BOPD gross (4,247 BOPD WI) during the Quarter, its second highest quarterly production average since second quarter 2015, despite no development wells being drilled since first quarter 2018. During the Quarter, Gran Tierra initiated a waterflood project designed to increase oil recovery in the Cumplidor field in the Putumayo-7 Block. The Company plans to monitor waterflood performance and, based on results, expects to identify future development drilling locations. Shareholder Returns: Share Buybacks: Pursuant to Gran Tierra’s current normal course issuer bid (“NCIB”), the Company has purchased approximately 36 million of its shares of common stock since the commencement of the NCIB on September 1, 2022, representing approximately 9.7% of shares outstanding as of June 30, 2022. During the Quarter alone, the Company bought back approximately 13 million shares for approximately $10.7 million. Bond Buybacks: During the Quarter, Gran Tierra bought back approximately $8 million in face value of the Company’s 6.25% senior notes due February 2025 (the "2025 bonds"). Since starting bond buybacks, the Company has purchased a total of $28 million in face value of the 2025 bonds, which represents approximately 9.4% of the outstanding 2025 bonds. The cost of the 2025 bond buybacks during the Quarter alone was approximately $6.8 million, representing a discount of about 15% to the face value of the purchased 2025 bonds. 1Gran Tierra's total current average production is for the period of April 1, 2023, to April 4, 2023. Corporate Presentation: Gran Tierra’s Corporate Presentation is available on the Company website at www.grantierra.com. Contact Information: For investor and media inquiries please contact: Gary Guidry President & Chief Executive Officer Ryan Ellson Executive Vice President & Chief Financial Officer Rodger Trimble Vice President, Investor Relations +1-403-265-3221 info@grantierra.com About Gran Tierra Energy Inc. Gran Tierra Energy Inc. together with its subsidiaries is an independent international energy company currently focused on oil and natural gas exploration and production in Colombia and Ecuador. The Company is currently developing its existing portfolio of assets in Colombia and Ecuador and will continue to pursue additional growth opportunities that would further strengthen the Company’s portfolio. The Company’s common stock trades on the NYSE American, the Toronto Stock Exchange and the London Stock Exchange under the ticker symbol GTE. Additional information concerning Gran Tierra is available at www.grantierra.com. Information on the Company’s website (including the Corporate Presentation referenced above) does not constitute a part of this press release. Investor inquiries may be directed to info@grantierra.com or (403) 265-3221. Gran Tierra’s U.S. Securities and Exchange Commission (“SEC”) filings are available on the SEC website at www.sec.gov. The Company’s Canadian securities regulatory filings are available on SEDAR at www.sedar.com and UK regulatory filings are available on the National Storage Mechanism (“the NSM”) website at data.fca.org.uk. Gran Tierra's filings on the SEC, SEDAR and the NSM websites are not incorporated by reference into this press release. Forward Looking Statements and Legal Advisories: This press release contains opinions, forecasts, projections, and other statements about future events or results that constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and financial outlook and forward-looking information within the meaning of applicable Canadian securities laws (collectively, “forward-looking statements”). The use of the words “expect,” “plan,” “can,” “will,” “should,” “guidance,” “forecast,” “signal,” “progress,” and “believes,” derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this press release contains forward-looking statements regarding: the Company’s expected future production (including as a result of our testing results), the Company’s drilling program, the Company’s potential debt repayments and share repurchases. The forward-looking statements contained in this press release reflect several material factors and expectations and assumptions of Gran Tierra including, without limitation, that Gran Tierra will continue to conduct its operations in a manner consistent with its current expectations, pricing and cost estimates (including with respect to commodity pricing and exchange rates), and the general continuance of assumed operational, regulatory and industry conditions in Colombia and Ecuador, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned. Among the important factors that could cause actual results to differ materially from those indicated by the forward-looking statements in this press release are: Gran Tierra’s operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events (including the ongoing COVID-19 pandemic); global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, the Russian invasion of Ukraine, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC, and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than Gran Tierra currently predicts, which could cause Gran Tierra to further modify its strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; the ability of Gran Tierra to execute its business plan and realize expected benefits from current initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that Gran Tierra does not receive the anticipated benefits of government programs, including government tax refunds; Gran Tierra’s ability to comply with financial covenants in its credit agreement and indentures and make borrowings under any credit agreement; capital market disruptions; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the Securities and Exchange Commission, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2022 and its other filings with the Securities and Exchange Commission. These filings are available on the Securities and Exchange Commission website at sec.gov and SEDAR at www.sedar.com. The forward-looking statements contained in this press release are based on certain assumptions made by Gran Tierra based on management’s experience and other factors believed to be appropriate. Gran Tierra believes these assumptions to be reasonable at this time, but the forward-looking statements are subject to risk and uncertainties, many of which are beyond Gran Tierra’s control, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, the unprecedented nature of the current economic downturn, pandemic and industry decline may make it particularly difficult to identify risks or predict the degree to which identified risks will impact Gran Tierra’s business and financial condition. All forward-looking statements are made as of the date of this press release and the fact that this press release remains available does not constitute a representation by Gran Tierra that Gran Tierra believes these forward-looking statements continue to be true as of any subsequent date. Actual results may vary materially from the expected results expressed in forward-looking statements. Gran Tierra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable law. Presentation of Oil and Gas Information: References to a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume. Gran Tierra’s reported production is a mix of light crude oil and medium and heavy crude oil for which there is not a precise breakdown since the Company’s oil sales volumes typically represent blends of more than one type of crude oil. Well test results should be considered as preliminary and not necessarily indicative of long-term performance or of ultimate recovery. Well log interpretations indicating oil and gas accumulations are not necessarily indicative of future production or ultimate recovery. If it is indicated that a pressure transient analysis or well-test interpretation has not been carried out, any data disclosed in that respect should be considered preliminary until such analysis has been completed. References to thickness of “oil pay” or of a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume.

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From: LoneClone	4/12/2023 12:41:03 PM
	of 24755

Gran Tierra Energy Announces Contract Agreement for the Suroriente Block ca.finance.yahoo.com Gran Tierra Energy Inc. Tue, April 11, 2023 at 3:40 p.m. PDT·10 min read CALGARY, Alberta, April 11, 2023 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE:GTE) is pleased to announce that the Company has entered into an agreement with Ecopetrol S.A. (“Ecopetrol”), the national oil company of Colombia, by which the parties renegotiated the terms and the duration of the contract for the Suroriente Block (“Suroriente”) in the Department of Putumayo, which was scheduled to end in mid-2024 (the “Agreement”). All dollar amounts are in United States (“U.S.”) dollars unless otherwise indicated. The Agreement provides an opportunity to add significant value, as well as economic life, to Suroriente by continuing its duration for 20 years from the Agreement’s effective date. The additional term of the contract allows long-term investment in infrastructure and work programs to enhance oil recovery efficiency in existing fields, and appraisal drilling to potentially prolong the life of the fields. Gran Tierra will continue to be the operator of Suroriente and is committing to a capital investment program of $123 million over a three-year period from the Agreement’s effective date, expected to be funded by Gran Tierra’s internal cash flow. The Agreement is subject to certain conditions precedent including regulatory approval by the Superintendence of Industry and Commerce of Colombia (“SIC”). The satisfaction of such conditions precedent will determine the Agreement’s effective date. Gran Tierra became the operator of Suroriente in March 2019 with a 52% working interest (“WI”), with Ecopetrol holding the remaining 48% WI. Since becoming the operator, Gran Tierra has been able to increase 100% gross oil production from an average of 6,203 barrels (“bbl”) of oil per day (“bopd”) in February 2019 to an average of 8,167 bopd during first quarter 2023, an increase of 32%. The Company has also expanded the Cohembi enhanced oil recovery (“EOR”) project, which is designed to increase the ultimate oil recovery and value of the block. Suroriente’s first quarter 2023 average production of 8,167 bopd gross (4,247 bopd WI) was its second highest quarterly average production average since second quarter 2015, despite no development wells being drilled since first quarter 2018. The Agreement further strengthens and consolidates Gran Tierra's position as a premier operator and the top contracted area holder in the Putumayo Basin and provides continuity to the Company’s long-term business relationship with Ecopetrol. Gran Tierra is the operator of 100% of its Putumayo blocks. The Agreement is also consistent with Gran Tierra's focused strategy to grow the Company's reserves and its portfolio of development and exploration opportunities in the proven, underexplored Putumayo Basin, with access to established infrastructure. By continuing the tenure of its operatorship of Suroriente, Gran Tierra expects to expand the EOR project in the block through long-term investments, which the Company forecasts to further increase value for all stakeholders. The capital commitment associated with the Agreement also aligns with the Company’s preexisting long-term plans to develop Suroriente. Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented: “The Agreement represents a unique and significant opportunity in Colombia in terms of scale and upside potential while maintaining our long-term partnership with Ecopetrol in the prolific Putumayo Basin. We are excited by the opportunity to continue to develop and expand Suroriente's already successful EOR project in the N Sand zone of the Cohembi oil field. By securing the Agreement, Gran Tierra can now commit to long-term capital projects and development programs with plans of optimizing the oil recovery and value for the Suroriente Block. We believe the combination of Gran Tierra's robust operational expertise in the Putumayo Basin and Ecopetrol’s technical knowledge will continue our joint success in the Suroriente Block.” Contact Information For investor and media inquiries please contact: Gary Guidry President & Chief Executive Officer Ryan Ellson Executive Vice President & Chief Financial Officer Rodger Trimble Vice President, Investor Relations +1-403-265-3221 info@grantierra.com About Gran Tierra Energy Inc. Gran Tierra Energy Inc. together with its subsidiaries is an independent international energy company currently focused on oil and natural gas exploration and production in Colombia and Ecuador. The Company is currently developing its existing portfolio of assets in Colombia and Ecuador and will continue to pursue additional growth opportunities that would further strengthen the Company’s portfolio. The Company’s common stock trades on the NYSE American, the Toronto Stock Exchange and the London Stock Exchange under the ticker symbol GTE. Additional information concerning Gran Tierra is available at www.grantierra.com. Information on the Company’s website does not constitute a part of this press release. Investor inquiries may be directed to info@grantierra.com or (403) 265-3221. Gran Tierra’s U.S. Securities and Exchange Commission (“SEC”) filings are available on the SEC website at www.sec.gov. The Company’s Canadian securities regulatory filings are available on SEDAR at www.sedar.com and UK regulatory filings are available on the National Storage Mechanism (“the NSM”) website at data.fca.org.uk. Gran Tierra's filings on the SEC, SEDAR and the NSM websites are not incorporated by reference into this press release. Forward Looking Statements and Legal Advisories: This press release contains opinions, forecasts, projections, and other statements about future events or results that constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and financial outlook and forward-looking information within the meaning of applicable Canadian securities laws (collectively, “forward-looking statements”). The use of the words “expect,” “plan,” “can,” “will,” “should,” “guidance,” “forecast,” “signal,” “progress,” and “believes,” derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this press release contains forward-looking statements regarding: the satisfaction of the conditions to the closing of the Agreement, future production and prospects, and the anticipated benefits of the Agreement to Gran Tierra, its shareholders and other stakeholders. The forward-looking statements contained in this press release reflect several material factors and expectations and assumptions of Gran Tierra including, without limitation, that Gran Tierra will continue to conduct its operations in a manner consistent with its current expectations, pricing and cost estimates (including with respect to commodity pricing and exchange rates), and the general continuance of assumed operational, regulatory and industry conditions in Colombia and Ecuador, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned. Among the important factors that could cause actual results to differ materially from those indicated by the forward-looking statements in this press release are: Gran Tierra’s operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events (including the ongoing COVID-19 pandemic); global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, the Russian invasion of Ukraine, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC, and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than Gran Tierra currently predicts, which could cause Gran Tierra to further modify its strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; the ability of Gran Tierra to execute its business plan and realize expected benefits from current initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of EOR and stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that Gran Tierra does not receive the anticipated benefits of government programs, including government tax refunds; Gran Tierra’s ability comply with financial covenants in its credit agreement and indentures and make borrowings under any credit agreement; capital market disruptions; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the Securities and Exchange Commission, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2022 and its other filings with the Securities and Exchange Commission. These filings are available on the Securities and Exchange Commission website at sec.gov and SEDAR at www.sedar.com. The forward-looking statements contained in this press release are based on certain assumptions made by Gran Tierra based on management’s experience and other factors believed to be appropriate. Gran Tierra believes these assumptions to be reasonable at this time, but the forward-looking statements are subject to risk and uncertainties, many of which are beyond Gran Tierra’s control, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, the unprecedented nature of the current economic downturn, pandemic and industry decline may make it particularly difficult to identify risks or predict the degree to which identified risks will impact Gran Tierra’s business and financial condition. All forward-looking statements are made as of the date of this press release and the fact that this press release remains available does not constitute a representation by Gran Tierra that Gran Tierra believes these forward-looking statements continue to be true as of any subsequent date. Actual results may vary materially from the expected results expressed in forward-looking statements. Gran Tierra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable law. Presentation of Oil and Gas Information: References to a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume. Gran Tierra’s reported production is a mix of light crude oil and medium and heavy crude oil for which there is not a precise breakdown since the Company’s oil sales volumes typically represent blends of more than one type of crude oil. Well test results should be considered as preliminary and not necessarily indicative of long-term performance or of ultimate recovery. Well log interpretations indicating oil and gas accumulations are not necessarily indicative of future production or ultimate recovery. If it is indicated that a pressure transient analysis or well-test interpretation has not been carried out, any data disclosed in that respect should be considered preliminary until such analysis has been completed. References to thickness of “oil pay” or of a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume.

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From: LoneClone

4/18/2023 12:51:50 PM

Southern Energy Announces Fourth Quarter and Year End 2022 Financial and Operating Results

accesswire.com

Tuesday, April 18, 2023 2:02 AM

CALGARY, AB / ACCESSWIRE / April 18, 2023 / Southern Energy Corp. ("Southern" or the "Company") (TSXV:SOU)(AIM:SOUC)(OTCQX:SOUTF), an established producer with natural gas and light oil assets in Mississippi, announces the release of its fourth quarter and year end December 31, 2022, financial and operating results. Selected financial and operational information is outlined below and should be read in conjunction with the Company's audited consolidated financial statements (the "Financial Statements") and related management's discussion and analysis (the "MD&A") for the three months and year ended December 31, 2022 and annual information form ("AIF") for the year ended December 31, 2022, which are available on the Company's website at www.southernenergycorp.com and have been filed on SEDAR.

All figures referred to in this news release are denominated in U.S. dollars, unless otherwise noted.

FOURTH QUARTER AND YEAR END 2022 HIGHLIGHTS

$3.1 million of adjusted funds flow from operations1 in Q4 2022 ($0.02 per share basic and diluted) compared $1.4 million in Q4 2021 ($0.02 per share basic and diluted) and $17.2 million for the year ended December 31, 2022 ($0.16 per share basic and $0.14 per share diluted), an increase of 500% from the same period in 2021
Net earnings of $1.7 million ($0.01 per share basic and diluted) and $9.3 million ($0.09 per share basic and $0.08 per share diluted) for the three and twelve months ended December 31, 2022; as compared to net earnings of $3.3 million ($0.06 per share basic and $0.05 per share diluted) and $10.1 million ($0.24 per share basic and $0.19 per share diluted) in the same period of 2021. 2021 results included the one-time recognition of an impairment recovery and gain on debt retirement
Petroleum and natural gas sales were $9.8 million in Q4 2022 and $45.2 million for the full year 2022, an increase of 37% and 127% from the same periods in 2021, respectively
Average production of 16,084 Mcfe/d2 (2,681 boe/d) (96% natural gas) during Q4 2022 and 15,584 Mcfe/d3 (2,597 boe/d) (95% natural gas) for the full year 2022, an increase of 26% and 24% from the same periods in 2021, respectively
Average realized natural gas and oil prices for Q4 2022 of $6.35/Mcf and $81.98/bbl, respectively, reflecting the benefit of strategic access to premium-priced US sales hubs in a geographic region with strong industrial and power generation natural gas demand
On July 7, 2022, successfully closed a $17.5 million bought deal prospectus offering in Canada and a $13.5 million placing in the UK, raising aggregate gross proceeds of $31.0 million
Successfully negotiated a $25.0 million borrowing capacity increase in respect of its senior secured term loan ("Credit Facility") to increase the total Credit Facility to $35.0 million
Exited Q4 2022 with positive net cash1 of $13.4 million
In November 2022, spud three horizontal wells from the 18-10 padsite at Gwinville which included the first City Bank appraisal well

Ian Atkinson, President and CEO of Southern, commented:

"Our Q4 and full year 2022 results have provided a preview of what Southern can and expects to achieve, with its strong underlying production base and technical ability to organically grow our assets at constructive natural gas prices. Our equity financing in July and Credit Facility expansion in September have put the Company in a position to weather the natural gas price volatility and provide flexibility and patience as we continue to work towards our goal to reach 25,000 boe/d. We're excited to build upon the learnings from our three well appraisal program in Q2, as well as the seven wells drilled as part of the follow up program at Gwinville which will continue to translate into future drilling and cost efficiencies when the program resumes. We have positioned ourselves to re-ignite our organic growth in a more supportive natural gas price environment and will continue to seek growth opportunity to increase significant shareholder value as we continue through the year."

Financial Highlights

	Three months ended December 31,					Year ended December 31,
(000s, except $ per share)	2022		2021			2022		2021
Petroleum and natural gas sales	$	9,830	$	7,151		$	45,217	$	19,942
Net earnings		1,749		3,311			9,299		10,093
Net earnings per share
Basic		0.01		0.06			0.09		0.24
Fully diluted		0.01		0.05			0.08		0.19
Adjusted funds flow from operations (1)		3,059		1,426			17,156		2,860
Adjusted funds flow from operations per share (1)
Basic		0.02		0.02			0.16		0.07
Fully diluted		0.02		0.02			0.14		0.05
Capital expenditures		10,218		1,755			30,434		2,562
Weighted average shares outstanding
Basic		137,378		58,087			108,144		42,545
Fully diluted		146,797		73,895			122,972		55,047
As at period end
Basic common shares outstanding		138,057		78,122			138,057		78,122
Total assets		97,652		46,212			97,652		46,212
Non-current liabilities		12,817		12,609			12,817		12,609
Positive net cash (net debt) (1)	$	13,437	$	(6,431	)	$	13,437	$	(6,431	)

Note:

See "Reader Advisories - Specified Financial Measures".

Outlook

In order to be diligent in protecting the Company balance sheet and respond to the current low natural gas prices, Southern has moderated and taken a pause on the Gwinville organic growth program. Southern has left four drilled, uncompleted wells ("DUCs") that can be quickly completed and brought online through Southern's 100% owned equipment at higher natural gas prices. Southern currently has $23.0 million of unused capacity on its Credit Facility, which can be utilized to complete the DUCs at supportive natural gas prices or be opportunistic with counter cyclical inorganic growth opportunities.

Natural gas prices have been under pressure in 2023 coming off a mild winter in North America and increased production from the depletion of the DUC well inventory as a result of higher prices in 2022. In Q1 2023, Southern was protected from some of the volatility with a costless collar on 2,000 MMBtu/d of production with a floor price of $3.50/MMBtu. To further protect against the volatility, Southern has entered into a basis swap transaction to secure a premium to NYMEX of $0.32 per MMBtu on 1,000 MMBtu/d from April 1, 2023 to October 31, 2023. The Company continues to monitor the basis differential prices and is prepared to hedge additional basis exposure at elevated basis premiums.

Calvin Yau, Chief Financial Officer of Southern, commented:

"2022 was a record year for Southern thanks to strong production from our base assets and the Gwinville appraisal program along with the continued strength of natural gas spot and basis pricing premiums to NYMEX in Southeastern U.S., building a solid foundation for Southern as we enter 2023. While we were excited to begin our long-term drilling program, we felt it was prudent to take a pause and protect our balance sheet in order to be flexible and able to capitalize on potential opportunities or quickly resume our organic growth program at the right time. Southern is in an enviable position being able to operate in a nimble and dynamic way around our drilling program, and with a constructive outlook for the U.S. natural gas market in the short to medium term, we are confident in maximising value from our assets by sensible well management.

"The Company's long-term strategy remains consistent, with an unwavering commitment to environmental, social and governance ("ESG") principles that support the continued development and consolidation of prolific reservoirs that are outside of the more expensive shale basins. Cost savings and financial discipline will remain a priority through the continued enhancement of operations and the ongoing evaluation of opportunities to reduce operating and capital costs.

"Southern thanks all of its stakeholders for their ongoing support and looks forward to providing future updates on operational activities and continuing to create shareholder value."

Operational Update

The Company continues to flow back the Gwinville 18-10 #1 City Bank well, with load fluid recovery of approximately 9%. Based on historic vertical and early generation horizontal well completions in the City Bank reservoir in Gwinville, peak gas rates are not expected until the load fluid recovery is closer to 20%, which is expected to be towards the end of this quarter. Early gas rates are encouraging and Southern is excited to provide further operational updates in Q2 2023 as the modern generation City Bank type curve results are established.

Remediation plans for the 18-10 #3 Upper Selma Chalk well that experienced a mechanical integrity issue with the production casing during completion operations continue to be finalized, with field execution expected in late Q2 2023.

The four wells that are awaiting completion include our first two Lower Selma Chalk laterals, along with our second City Bank lateral and one Upper Selma Chalk lateral. These four wells are some of our longest laterals to-date. They were drilled with an average lateral length of approximately 5,400' and were steered within the high-graded intervals for an average of 95% of the wellbore length. The two padsites can be brought on production within a matter of weeks once completion operations are resumed.

Corporate Presentation

A new corporate presentation dated April 2023 is now available on the Company website at www.southernenergycorp.com.

Qualified Person's Statement

Gary McMurren, COO, who has over 22 years of relevant experience in the oil industry and has approved the technical information contained in this announcement. Mr. McMurren is registered as a Professional Engineer with the Association of Professional Engineers and Geoscientists of Alberta and received a Bachelor of Science degree in Chemical Engineering (with distinction) from the University of Alberta.

For further information about Southern, please visit our website at www.southernenergycorp.com or contact:

Southern Energy Corp. Ian Atkinson (President and CEO) Calvin Yau (CFO)	+1 587 287 5401 +1 587 287 5402
Strand Hanson Limited - Nominated & Financial Adviser James Spinney / James Bellman Canaccord Genuity - Joint Broker Henry Fitzgerald-O'Connor / James Asensio	+44 (0) 20 7409 3494 +44 (0) 20 7523 8000
Stifel Nicolaus Europe Limited - Joint Broker Callum Stewart / Ashton Clanfield Tennyson Securities - Joint Broker Peter Krens / Pav Sanghera Camarco Owen Roberts / Billy Clegg / Hugo Liddy	+44 (0) 20 7710 7600 +44 (0) 20 7186 9033 +44 (0) 20 3757 4980

About Southern Energy Corp.

Southern Energy Corp. is a natural gas exploration and production company characterized by a stable, low-decline production base, a significant low-risk drilling inventory and strategic access to premium commodity pricing in North America. Southern has a primary focus on acquiring and developing conventional natural gas and light oil resources in the southeast Gulf States of Mississippi, Louisiana, and East Texas. Our management team has a long and successful history working together and have created significant shareholder value through accretive acquisitions, optimization of existing oil and natural gas fields and the utilization of re-development strategies utilizing horizontal drilling and multi-staged fracture completion techniques.

READER ADVISORY

MCFE Disclosure. Natural gas liquids volumes are recorded in barrels of oil (bbl) and are converted to a thousand cubic feet equivalent (Mcfe) using a ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl). 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). Mcfe and boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl or a Mcfe conversion ratio of 1 bbl:6 Mcf is based in an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of oil as compared with natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf:1 bbl or a Mcfe conversion ratio of 1 bbl:6 Mcf may be misleading as an indication of value.

Throughout this press release, "crude oil" or "oil" refers to light and medium crude oil product types as defined by National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). References to "NGLs" throughout this press release comprise pentane, butane, propane, and ethane, being all NGLs as defined by NI 51-101. References to "natural gas" throughout this press release refers to conventional natural gas as defined by NI 51-101.

Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with National Instrument 51 101 - Standards of Disclosure for Oil and Gas Activities. Boe may be misleading, particularly if used in isolation.

Abbreviations. Please see below for a list of abbreviations used in this press release.

bbl barrels
bbl/d barrels per day
boe barrels of oil
boe/d barrels of oil per day
Mcf thousand cubic feet
Mcf/d thousand cubic feet per day
MMcf million cubic feet
MMcf/d million cubic feet per day

Mcfe thousand cubic feet equivalent
Mcfe/d thousand cubic feet equivalent per day

MMBtu million British thermal units
MMBtu/d million British thermal units per day

Forward Looking Statements. Certain information included in this press release constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, statements concerning the Company's asset base including the development of the Company's assets, oil and natural gas production levels, including the objective of achieving production of 25,000 boe/d, the Company's capital budget, expectations regarding material reserves, anticipated operational results in 2023 including, but not limited to, capital expenditures and drilling plans, expectations regarding commodity prices, the performance characteristics of the Company's oil and natural gas properties, the Company's hedging strategy, the ability of the Company to achieve drilling success consistent with management's expectations, the sources of funding for the Company's activities, the effect of market conditions and the COVID-19 pandemic on the Company's performance, Southern's planned ESG initiatives, expectations regarding the use of proceeds from all sources, including the Company's credit facilities, the availability and renewal of the Credit Facility and future amendments thereto, future organic and inorganic growth and acquisition opportunities within the resource market, and costs/debt reducing activities. Statements relating to "reserves" and "recovery" are also deemed to be forward- looking statements, as 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.

The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Southern, including the timing of and success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, the availability and performance of drilling rigs, facilities and pipelines, the geological characteristics of Southern's properties, the characteristics of the Company's assets, the successful application of drilling, completion and seismic technology, the benefits of current commodity pricing hedging arrangements, Southern's ability to enter into future derivative contracts on acceptable terms, Southern's ability to secure financing on acceptable terms, prevailing weather conditions, prevailing legislation, as well as regulatory and licensing requirements, affecting the oil and gas industry, the Company's ability to obtain all requisite permits and licences, prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products, royalty regimes and exchange rates, the impact of inflation on costs, the application of regulatory and licensing requirements, the Company's ability to obtain all requisite permits and licences, the availability of capital, labour and services, the creditworthiness of industry partners, and the Company's ability to source and complete asset acquisitions.

Although Southern believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Southern can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, regulatory risks, and health, safety and environmental risks), constraint in the availability of labour, supplies, or services, the impact of COVID-19 and variant strains of the virus, commodity price and exchange rate fluctuations, geo-political risks, political and economic instability abroad, wars (including the Russo-Ukrainian War), hostilities, civil insurrections, inflationary risks including potential increases to operating and capital costs, changes in legislation impacting the oil and gas industry, adverse weather or break-up conditions, and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. The Russo-Ukrainian War is particularly noteworthy, as this conflict has the potential to disrupt the global supply of oil and gas, and its full impact remains uncertain. These and other risks are set out in more detail in Southern's MD&A and AIF.

The forward-looking information contained in this press release is made as of the date hereof and Southern undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this press release is expressly qualified by this cautionary statement.

Future Oriented Financial Information. This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Southern's prospective results of operations, cash flow, increased capacity under the credit facility, capital expenditures and payout of wells, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was approved by management as of the date of this document and was provided for the purpose of providing further information about Southern's future business operations. Southern and its management believe that FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Southern disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Southern's guidance. The Company's actual results may differ materially from these estimates.

Specified Financial Measures. This press release provides various financial measures that do not have a standardized meaning prescribed by IFRS, including non-IFRS financial measures, non-IFRS financial ratios and capital management measures. These specified financial measures may not be comparable to similar measures presented by other issuers. Southern's method of calculating these measures may differ from other companies and accordingly, they may not be comparable to measures used by other companies. Adjusted funds flow from operations, operating netback, adjusted working capital and net debt are not recognized measures under IFRS. Readers are cautioned that these specified financial measures should not be construed as alternatives to other measures of financial performance calculated in accordance with IFRS. These specified financial measures provide additional information that management believes is meaningful in describing the Company's operational performance, liquidity and capacity to fund capital expenditures and other activities. Please see below for a brief overview of all specified financial measures used in this release and refer to the Company's MD&A for additional information relating to specified financial measures, which is available on the Company's website at www.southernenergycorp.com and filed on SEDAR.

"Adjusted Funds Flow from Operations" (non-IFRS financial measure) is calculated based on cash flow from operative activities before changes in non-cash working capital and cash decommissioning expenditures. Management uses adjusted funds flow from operations as a key measure to assess the ability of the Company to finance operating activities, capital expenditures and debt repayments.

"Adjusted Funds Flow from Operations per Share" (non-IFRS financial measure) is calculated by dividing Adjusted Funds Flow from Operations by the number of Southern shares issued and outstanding.

"Operating Netback" (non-IFRS financial measure) equals total oil and natural gas sales less royalties, production taxes, operating expenses, transportation costs and realized gain / (loss) on derivatives. Management considers operating netback an important measure to evaluate its operational performance, as it demonstrates field level profitability relative to current commodity prices.

"Positive Net Cash (Net Debt)" (capital management measure) is monitored by Management, along with adjusted working capital, as part of its capital structure in order to fund current operations and future growth of the Company. Net debt is defined as long-term debt plus adjusted working capital surplus or deficit. Adjusted working capital is calculated as current assets less current liabilities, removing current derivative assets/liabilities, the current portion of bank debt, and the current portion of lease liabilities.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

1 See "Specified Financial Measures" under "Reader Advisory" below

2 Comprised of 107 bbl/d light and medium crude oil, 11 bbl/d NGLs and 15,376 Mcf/d conventional natural gas

3 Comprised of 116 bbl/d light and medium crude oil, 14 bbl/d NGLs and 14,804 Mcf/d conventional natural gas

SOURCE: Southern Energy Corp.

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From: LoneClone

5/3/2023 2:44:01 PM

Gran Tierra Energy Announces First Quarter 2023 Results

ca.finance.yahoo.com

Gran Tierra Energy Inc.
Tue, May 2, 2023 at 2:45 p.m. PDT·27 min read

First Quarter 2023 Total Average Production of 31,611 BOPD, Up 8% from One Year Ago

Second Quarter-To-Date 2023(1) Total Average Production of Approximately 32,400 BOPD

Net Loss of $10 Million, Net Income of $115 Million Over Last 12 Months

Adjusted EBITDA(2) of $89 Million, $459 Million Over Last 12 Months

Funds Flow from Operations(2) of $60 Million, $339 Million Over Last 12 Months

Cash Balance of $106 Million and Net Debt(2) of $466 Million, as of March 31, 2023

Colombia Development Campaign Progressing with 14 Wells Drilled in the Quarter and Another 4 Wells Drilled Second Quarter-To-Date 2023(1)

CALGARY, Alberta, May 02, 2023 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE:GTE) today announced the Company’s financial and operating results for the quarter ended March 31, 2023 (“the Quarter”). All dollar amounts are in United States dollars, and production amounts are on an average working interest (“WI”) before royalties basis unless otherwise indicated. Per barrel (“bbl”) and bbl per day (“BOPD”) amounts are based on WI sales before royalties. For per bbl amounts based on net after royalty (“NAR”) production, see Gran Tierra’s Quarterly Report on Form 10-Q filed May 2, 2023.

Key Highlights of the Quarter:

Production:

Gran Tierra’s total average production for the Quarter was 31,611 BOPD, up 8% from first quarter 2022 (“one year ago”) and decreased by 3% compared to fourth quarter 2022 (“the Prior Quarter”).

The Company’s second quarter-to-date(1) 2023 total average production has been approximately 32,400 BOPD.

Oil Price: The Brent oil price averaged $82.10 per bbl, down 16% from one year ago, and down 7% from the Prior Quarter.

Quality and Transportation Discounts: The Company’s quality and transportation discount narrowed to $18.45 per bbl, down from $19.74 per bbl in the Prior Quarter and was up from $12.56 per bbl one year ago. The Castilla oil differential increased to $15.17 per bbl from $6.38 per bbl one year ago (Castilla is the benchmark for the Company’s Middle Magdalena Valley Basin oil production). The Vasconia differential increased to $7.87 per bbl from $3.60 per bbl one year ago (Vasconia is the benchmark for the Company’s Putumayo Basin oil production). Differentials narrowed in March 2023 and continued to narrow in April 2023. The current(1) Castilla differential is approximately $11.30 per bbl and the Vasconia differential is approximately $6.30 per bbl.

Net Income: Gran Tierra incurred a net loss of $10 million, compared to net income of $14 million one year ago, and net income of $33 million in the Prior Quarter. The Company’s net income over the last 12 months was $115 million.

Basic and Diluted Earnings Per Share: Gran Tierra incurred a net loss of $0.03 per share, compared to net income of $0.09 per share in the Prior Quarter and $0.04 per share one year ago.

Adjusted EBITDA(2): Adjusted EBITDA(2) was $89 million compared to $119 million one year ago, and $109 million in the Prior Quarter. The Company’s trailing twelve-month Adjusted EBITDA(2) was $459 million, resulting in an annualized net debt(2) to Adjusted EBITDA(2) ratio of 1.0 times.

Funds Flow from Operations(2): Funds flow from operations(2) was $60 million, down 31% from one year ago and down 26% from the Prior Quarter. Over the last 12 months, Gran Tierra’s funds flow from operations(2) was $339 million.

Free Cash Flow(2): Gran Tierra generated free cash flow(2) of $73 million over the last twelve months. During the Quarter the Company’s capital expenditures exceeded funds flow from operations by approximately $11 million as a result of the Company’s front-end loaded 2023 development program which saw the drilling of 14 development wells in the Quarter, out of the total 2023 budgeted plan for 18-23 development wells.

Share Buybacks:

Share Buybacks: During the Quarter, pursuant to Gran Tierra’s current normal course issuer bid (“NCIB”), Gran Tierra purchased approximately 13.1 million shares, for a total purchase price of $10.7 million, at a weighted average price of approximately $0.82 per share. Since the commencement of the NCIB on September 1, 2022, Gran Tierra has purchased 35.8 million shares, representing approximately 9.7% of Gran Tierra’s outstanding shares as of June 30, 2022.

Bond Buybacks:

As part of Gran Tierra’s ongoing commitment to reduce its net debt(2), during the Quarter, the Company bought back $8.0 million in face value of Gran Tierra’s 6.25% senior notes due February 2025 (the “2025 bonds”). The cost of the 2025 bonds’ buyback was approximately $6.8 million, representing a discount of about 15% to the face value of the 2025 bonds.

Cash and Net Debt:

As of March 31, 2023, the Company had a cash balance of $106 million and net debt(2) of $466 million (net of the buyback of 2025 bonds described above).

Gran Tierra’s credit facility, with a capacity of up to $150 million, remains undrawn.

Additional Key Financial Metrics:

Capital Expenditures: Capital expenditures of $71 million were lower than the Prior Quarter’s level of $73 million and up from $41 million compared to a year ago. During the Quarter, Gran Tierra drilled 14 development wells in Colombia.

Oil Sales: Gran Tierra generated oil sales of $144 million, down 17% from one year ago and down 11% from the Prior Quarter. The changes in oil sales were driven primarily by the decrease in Brent oil price and widening of quality and transportation discounts over the same time periods.

Operating Netback(2)(3): The Company’s operating netback(2)(3) was $35.18 per bbl, down 33% from one year ago and down 9% from the Prior Quarter. As with oil sales, changes in operating netback were largely driven by the decrease in Brent oil price and widening of quality and transportation discounts over the same time periods.

Operating Expenses: Compared to the Prior Quarter, Gran Tierra’s operating expenses decreased 7% to $14.59 per bbl, down from $15.61 per bbl, primarily due to lower workover activities in the Quarter. Compared to one year ago, operating expenses increased by 9% on a per bbl basis, due to higher lifting costs mainly attributed to equipment rentals costs related to operations in Ecuador.

General and Administrative (“G&A”) Expenses: G&A expenses before stock-based compensation were $3.95 per bbl, up from $2.71 per bbl in the Prior Quarter.

Cash Netback: Cash netback per bbl was $21.16, compared to $27.54 in the Prior Quarter as a result of a decrease in Brent price of $6.53 per bbl. Compared to one year ago, cash netback per bbl only decreased $12.20 from $33.36, despite a $15.80 per bbl decrease in the Brent oil price over the same period.

Message to Shareholders

Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented: “During the Quarter, Gran Tierra completed a significant portion of its development campaign with the drilling of 14 development wells in three of our major fields which have been producing oil at rates in line with our expectations. The drilling of these wells is a testament to our team's commitment to operational excellence and their ability to execute our capital program efficiently. By completing the majority of our development program in the first three months of 2023, we expect to benefit from higher oil production rates for the remainder of the year with the goal of maximizing our production and cash flow. We continued to see positive results from our ongoing waterfloods across our operations primarily in Suroriente and Acordionero and are beginning to see positive results in our polymer flood in Acordionero.

We are very pleased with our recently announced agreement with Ecopetrol, the national oil company of Colombia, by which Gran Tierra and Ecopetrol renegotiated the agreement for the Suroriente Block in the Putumayo Basin, which was scheduled to end in mid-2024. This agreement provides an opportunity to add significant value, as well as economic life, to Suroriente by continuing its duration for 20 years. The additional term of the agreement allows long-term investment in infrastructure and work programs to enhance oil recovery efficiency in existing fields, and appraisal drilling to potentially prolong the life of the fields. We are also excited to recommence exploration drilling during second half 2023.”

Operations Update:

Colombia Development Campaign:

Acordionero:

Development drilling resumed in January 2023 with a 10-well program. Eight of the wells were drilled by the end of the Quarter with 5 on production, two on injection and one in progress.

As a result of the program and continued good performance of the field’s enhanced oil recovery via waterflood, Acordionero has averaged approximately 19,000 BOPD during second quarter-to-date 2023(1), which is the highest level since May 2019.

During the Quarter, Gran Tierra achieved a new water injection record of approximately 65,000 bbl of water injected per day (“bwipd”) up from 59,894 bwipd in first quarter 2022.

The polymer flood pilot was expanded with the start up of a second polymer injection well during the Quarter, with a third polymer injection well planned for second quarter 2023. Acordionero’s polymer flood pilot is expected to increase the field’s ultimate oil recovery.

Costayaco:

Four wells were drilled in Costayaco during the Quarter: Two producers are currently being completed with tie-in expected in early May 2023 and two water injection wells are completed and expected to begin injection during second quarter 2023. Two additional producers and one additional injector remain to be drilled as part of the Costayaco development plan for 2023. Completion and stimulation of the producing wells and waterflood optimization through additional injection are expected to continue to grow production in Costayaco throughout the year.

Costayaco-53 set a new record low for the amount of time to drill in Costayaco, coming in at just over 9 days from spud to rig release.

Moqueta:

Two wells were drilled in Moqueta during the Quarter and both are on production and awaiting stimulation. Two additional development wells are planned in 2023 along with two conversions to injector wells that are expected to grow production and optimize waterflood in Moqueta.

Suroriente:

On April 11, 2023 the Company announced it had entered into an agreement with Ecopetrol S.A. (“Ecopetrol”), the national oil company of Colombia, by which the parties renegotiated the agreement for the Suroriente Block (“Suroriente”) in the Department of Putumayo, which was scheduled to end in mid-2024 (the “Agreement”).

The Agreement provides an opportunity to add significant value, as well as economic life, to Suroriente by continuing its duration for 20 years from the Agreement's effective date. The additional term of the contract allows long-term investment in infrastructure and work programs to enhance oil recovery efficiency in existing fields, and appraisal drilling to potentially prolong the life of the fields. Gran Tierra will continue to be the operator of Suroriente and is committing to a capital investment program of $123 million over a three-year period from the Agreement's effective date, expected to be funded by Gran Tierra's internal cash flow.

The Agreement is subject to certain conditions precedent including regulatory approval by the Superintendence of Industry and Commerce of Colombia (“SIC”). The satisfaction of such conditions precedent will determine the Agreement's effective date.

Exploration Campaign:

Gran Tierra plans to drill four wells in Ecuador, three in the Charapa Block to appraise the discovery in the Hollin Formation and one in the Chanangue Block during the second half of 2023.

Gran Tierra has completed the selection process and secured a drilling rig, which the Company plans to mobilize from Colombia to Ecuador.

Gran Tierra expects to drill between 4 to 6 exploration wells in 2023 in Colombia and Ecuador combined.

Financial and Operational Highlights (all amounts in $000s, except per share and bbl amounts)

	Three Months Ended March 31,						Three Months Ended December 31,
		2023			2022			2022

Net (Loss) Income	$	(9,700	)	$	14,119		$	33,275
Per Share - Basic and Diluted	$	(0.03	)	$	0.04		$	0.09

Oil Sales	$	144,190		$	174,569		$	162,637
Operating Expenses		(41,369	)		(34,935	)		(46,119	)
Transportation Expenses		(3,066	)		(2,834	)		(2,433	)
Operating Netback(2)(3)	$	99,755		$	136,800		$	114,085

G&A Expenses Before Stock-Based Compensation	$	11,196		$	7,779		$	7,998
G&A Stock-Based Compensation Expense		1,500			4,557			2,673
G&A Expenses, Including Stock Based Compensation	$	12,696		$	12,336		$	10,671

Adjusted EBITDA(2)	$	88,677		$	119,378		$	108,828

EBITDA(2)	$	86,740		$	106,750		$	101,772

Net Cash Provided by Operating Activities	$	49,253		$	103,825		$	71,865

Funds Flow from Operations(2)	$	60,016		$	87,310		$	81,343

Capital Expenditures	$	71,062		$	41,483		$	72,887

Free Cash Flow(2)	$	(11,046	)	$	45,827		$	8,456

Average Daily Volumes (BOPD)
WI Production Before Royalties		31,611			29,362			32,595
Royalties		(6,085	)		(6,529	)		(6,880	)
Production NAR		25,526			22,833			25,715
Decrease (Increase) in Inventory		(355	)		(103	)		(53	)
Sales		25,171			22,730			25,662
Royalties, % of WI Production Before Royalties		19	%		22	%		21	%

Per bbl
Brent	$	82.10		$	97.90		$	88.63
Quality and Transportation Discount		(18.45	)		(12.56	)		(19.74	)
Royalties		(12.80	)		(18.67	)		(13.83	)
Average Realized Price		50.85			66.67			55.06
Transportation Expenses		(1.08	)		(1.08	)		(0.82	)
Average Realized Price Net of Transportation Expenses		49.77			65.59			54.24
Operating Expenses		(14.59	)		(13.34	)		(15.61	)
Operating Netback(2)(3)		35.18			52.25			38.63
G&A Expenses Before Stock-Based Compensation		(3.95	)		(2.97	)		(2.71	)
Realized Foreign Exchange (Loss) / Gain		(0.42	)		(0.43	)		0.68
Cash Settlements on Derivative Instruments		—			(3.28	)		—
Interest Expense, Excluding Amortization of Debt Issuance Costs		(3.90	)		(4.29	)		(3.38	)
Interest Income		0.27			—			0.15
Net Lease Payments		0.19			0.03			0.09
Current Income Tax Expense		(6.21	)		(7.95	)		(5.92	)
Cash Netback(2)	$	21.16		$	33.36		$	27.54

Share Information (000s)
Common Stock Outstanding, End of Period		333,069			368,421			346,151
Weighted Average Number of Common and Outstanding Stock - Basic		344,514			367,387			354,667
Weighted Average Number of Common and Outstanding Stock - Diluted		344,514			372,375			358,401

(1) Gran Tierra’s second quarter-to-date 2023 is from April 1 to May 1, 2023.
(2) Funds flow from operations, operating netback, net debt, cash netback, earnings before interest, taxes and depletion, depreciation and accretion (“DD&A”) (“EBITDA”) and EBITDA adjusted for non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, stock-based compensation expense, unrealized derivative instruments gains or losses, inventory impairment, gain on re-purchase of Senior Notes and other financial instruments gains or losses (“Adjusted EBITDA”), cash flow, free cash flow and net debt are non-GAAP measures and do not have standardized meanings under generally accepted accounting principles in the United States of America (“GAAP”). Cash flow refers to funds flow from operations. Free cash flow refers to funds flow from operations less capital expenditures. Refer to “Non-GAAP Measures” in this press release for descriptions of these non-GAAP measures and, where applicable, reconciliations to the most directly comparable measures calculated and presented in accordance with GAAP.
(3) Operating netback as presented is defined as oil sales less operating and transportation expenses. See the table titled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.

Conference Call Information:

Gran Tierra will host its first quarter 2023 results conference call on Wednesday, May 3, 2022, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time. Interested parties may access the conference call by registering at the following link: register.vevent.com. The call will also be available via webcast at www.grantierra.com.

Corporate Presentation:

Gran Tierra’s Corporate Presentation has been updated and is available on the Company website at www.grantierra.com.

Contact Information

For investor and media inquiries please contact:

Gary Guidry
President & Chief Executive Officer

Ryan Ellson
Executive Vice President & Chief Financial Officer

Rodger Trimble
Vice President, Investor Relations

+1-403-265-3221

info@grantierra.com

About Gran Tierra Energy Inc.
Gran Tierra Energy Inc. together with its subsidiaries is an independent international energy company currently focused on oil and natural gas exploration and production in Colombia and Ecuador. The Company is currently developing its existing portfolio of assets in Colombia and Ecuador and will continue to pursue additional new growth opportunities that would further strengthen the Company’s portfolio. The Company’s common stock trades on the NYSE American, the Toronto Stock Exchange and the London Stock Exchange under the ticker symbol GTE. Additional information concerning Gran Tierra is available at www.grantierra.com. Except to the extent expressly stated otherwise, information on the Company's website or accessible from our website or any other website is not incorporated by reference into and should not be considered part of this press release. Investor inquiries may be directed to info@grantierra.com or (403) 265-3221.

Gran Tierra's Securities and Exchange Commission (the “SEC”) filings are available on the SEC website at sec.gov. The Company’s Canadian securities regulatory filings are available on SEDAR at sedar.com and UK regulatory filings are available on the National Storage Mechanism website at data.fca.org.uk.

Forward Looking Statements and Legal Advisories:
This press release contains opinions, forecasts, projections, and other statements about future events or results that constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and financial outlook and forward looking information within the meaning of applicable Canadian securities laws (collectively, “forward-looking statements”). The use of the words “expect”, “plan”, “can,” “will,” “should,” “guidance,” “forecast,” “signal,” “progress” and “believes”, derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this press release contains forward-looking statements regarding: the Company’s expected future production and free cash flow, the Company’s targeted cash balance and uses of excess free cash flow, the Company’s drilling program and the Company’s expectations as to debt repayment, share repurchases, commodity prices and its positioning for the remainder of 2023. The forward- looking statements contained in this press release reflect several material factors and expectations and assumptions of Gran Tierra including, without limitation, that Gran Tierra will continue to conduct its operations in a manner consistent with its current expectations, pricing and cost estimates (including with respect to commodity pricing and exchange rates), and the general continuance of assumed operational, regulatory and industry conditions in Colombia and Ecuador, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned.

Among the important factors that could cause actual results to differ materially from those indicated by the forward-looking statements in this press release are: our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events (including the ongoing COVID-19 pandemic); global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, the Russian invasion of Ukraine, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC, such as its recent decision to cut production and other producing countries and resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict. which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute its business plan and realize expected benefits from current initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to comply with financial covenants in its credit agreement and indentures and make borrowings under any credit agreement; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the Securities and Exchange Commission, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2022 filed February 21, 2023 and its other filings with the SEC. These filings are available on the SEC website at sec.gov and on SEDAR at www.sedar.com.

The forward-looking statements contained in this press release are based on certain assumptions made by Gran Tierra based on management’s experience and other factors believed to be appropriate. Gran Tierra believes these assumptions to be reasonable at this time, but the forward-looking statements are subject to risk and uncertainties, many of which are beyond Gran Tierra’s control, which may cause actual results to differ materially from those implied or expressed by the forward looking statements. The risk that the assumptions on which the 2023 outlook are based prove incorrect may increase the later the period to which the outlook relates. In particular, the unprecedented nature of the pandemic and industry volatility may make it particularly difficult to identify risks or predict the degree to which identified risks will impact Gran Tierra’s business and financial condition. All forward-looking statements are made as of the date of this press release and the fact that this press release remains available does not constitute a representation by Gran Tierra that Gran Tierra believes these forward-looking statements continue to be true as of any subsequent date. Actual results may vary materially from the expected results expressed in forward-looking statements. Gran Tierra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable law. In addition, historical, current and forward-looking sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.

Non-GAAP Measures

This press release includes non-GAAP financial measures as further described herein. These non-GAAP measures do not have a standardized meaning under GAAP. Investors are cautioned that these measures should not be construed as alternatives to net income or loss, cash flow from operating activities or other measures of financial performance as determined in accordance with GAAP. Gran Tierra’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. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as to not imply that more emphasis should be placed on the non-GAAP measure.

Operating netback as presented is defined as oil sales less operating and transportation expenses. See the table entitled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.

Cash netback as presented is defined as net income or loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, derivative instruments gain or loss, cash settlement on derivative instruments, inventory impairment, gain on re-purchase of Senior Notes, and other financial instruments gain or loss. Management believes that operating netback and cash netback are useful supplemental measures for investors to analyze financial performance and provide an indication of the results generated by Gran Tierra’s principal business activities prior to the consideration of other income and expenses. A reconciliation from net income or loss to cash netback is as follows:

	Three Months Ended March 31,						Three Months Ended December 31,
Cash Netback - (Non-GAAP) Measure ($000s)		2023			2022			2022
Net (loss) income	$	(9,700	)	$	14,119		$	33,275
Adjustments to reconcile net income (loss) to cash netback
DD&A expenses		51,721			40,963			51,781
Deferred tax expense		15,277			18,713			(11,528	)
Stock-based compensation expense		1,500			4,557			2,673
Amortization of debt issuance costs		781			887			759
Non-cash lease expense		1,144			411			809
Lease payments		(606	)		(344	)		(532	)
Unrealized foreign exchange loss (gain)		514			(4,839	)		4,113
Derivative instruments loss		—			21,439			—
Cash settlements on derivative instruments		—			(8,596	)		—
Inventory impairment		475			—			—
Gain on re-purchase of Senior Notes		(1,090	)		—			—
Other financial instruments gain		—			—			(7	)
Cash netback	$	60,016		$	87,310		$	81,343

EBITDA, as presented, is defined as net income or loss adjusted for DD&A expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, stock-based compensation expense or recovery, unrealized derivative instruments gain or loss, inventory impairment, gain on repurchase of Senior Notes, and other financial instruments gain or loss. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows:

	Three Months Ended March 31,						Three Months Ended December 31,			Twelve Month Trailing March 31,
EBITDA - (Non-GAAP) Measure ($000s)		2023			2022			2022			2023
Net (loss) income	$	(9,700	)	$	14,119		$	33,275		$	115,210
Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA
DD&A expenses		51,721			40,963			51,781			191,038
Interest expense		11,836			12,128			10,750			46,201
Income tax expense		32,883			39,540			5,966			99,249
EBITDA	$	86,740		$	106,750		$	101,772		$	451,698
Non-cash lease expense		1,144			411			809			3,551
Lease payments		(606	)		(344	)		(532	)		(1,928	)
Unrealized foreign exchange loss (gain)		514			(4,839	)		4,113			15,604
Stock-based compensation expense		1,500			4,557			2,673			5,992
Unrealized derivative instruments loss		—			12,843			—			(12,843	)
Inventory impairment		475			—			—			475
Gain on re-purchase of Senior Notes		(1,090	)		—			—			(3,688	)
Other financial instruments gain		—			—			(7	)		(7	)
Adjusted EBITDA	$	88,677		$	119,378		$	108,828		$	458,854

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, derivative instruments gain or loss, cash settlement on derivative instruments, inventory impairment, gain on re-purchase of Senior Notes and other financial instruments gain or loss. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow from operations adjusted for capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to both funds flow from operations and free cash flow is as follows:

	Three Months Ended March 31,						Three Months Ended December 31,			Twelve Month Trailing March 31,
Funds Flow From Operations - (Non-GAAP) Measure ($000s)		2023			2022			2022			2023
Net (loss) income	$	(9,700	)	$	14,119		$	33,275		$	115,210
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses		51,721			40,963			51,781			191,038
Deferred tax expense		15,277			18,713			(11,528	)		21,904
Stock-based compensation expense		1,500			4,557			2,673			5,992
Amortization of debt issuance costs		781			887			759			3,422
Non-cash lease expense		1,144			411			809			3,551
Lease payments		(606	)		(344	)		(532	)		(1,928	)
Unrealized foreign exchange loss (gain)		514			(4,839	)		4,113			15,604
Derivative instruments loss		—			21,439			—			5,172
Cash settlements on derivative instruments		—			(8,596	)		—			(18,015	)
Inventory impairment		475			—			—			475
Gain on re-purchase of Senior Notes		(1,090	)		—			—			(3,688	)
Other financial instruments gain		—			—			(7	)		(7	)
Funds flow from operations	$	60,016		$	87,310		$	81,343		$	338,730
Capital expenditures	$	71,062		$	41,483		$	72,887		$	266,183
Free cash flow	$	(11,046	)	$	45,827		$	8,456		$	72,547

Net debt as of March 31, 2023, was $466 million, calculated using the sum of 6.25% Senior Notes and 7.75% Senior Notes, excluding deferred financing fees of $572 million, less cash and cash equivalents of $106 million.

Presentation of Oil and Gas Information

References to a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume. Gran Tierra’s reported production is a mix of light crude oil and medium and heavy crude oil for which there is not a precise breakdown since the Company’s oil sales volumes typically represent blends of more than one type of crude oil. Well test results should be considered as preliminary and not necessarily indicative of long-term performance or of ultimate recovery. Well log interpretations indicating oil and gas accumulations are not necessarily indicative of future production or ultimate recovery. If it is indicated that a pressure transient analysis or well-test interpretation has not been carried out, any data disclosed in that respect should be considered preliminary until such analysis has been completed. References to thickness of “oil pay” or of a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume.

This press release contains certain oil and gas metrics, including operating netback and cash netback, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. These metrics are calculated as described in this press release and management believes that they are useful supplemental measures for the reasons described in this press release.

Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

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From: LoneClone	5/4/2023 1:57:44 PM
	of 24755

CGX Energy Updates: Announces Filing of First Quarter Financial Statements and Drilling Operational Updates newsfilecorp.com Toronto, Ontario--(Newsfile Corp. - May 3, 2023) - CGX Energy Inc. (TSXV: OYL) ("CGX" or the "Company") announced today the release of its unaudited Consolidated Financial Statements for the first quarter of 2023, together with its Management, Discussion and Analysis - Quarterly Highlights (the "Financial Disclosures"). These Financial Disclosures will be posted on the Company's website at www.cgxenergy.com and on SEDAR at www.sedar.com. All values in the Financial Disclosures are in United States dollars unless otherwise stated. Company Highlights: Wei-1 Well Operational Update The Wei-1 well (the "Well") is currently being drilled by CGX and Frontera Energy Corporation ("Frontera") (the "JV Partners"). CGX holds a 32.00% participating interest with Frontera holding the remaining 68.00% participating interest in the Corentyne block. The Well, planned to be drilled to a total depth of 20,500 feet, to date has been successfully drilled to a depth of 19,142 feet. Wei-1 is located 14 kilometers west of the Kawa-1 discovery well announced by the JV Partners last year. Operations were interrupted when a wireline fluid sampling tool became stuck in the Well and was not recovered. An open hole sidetrack will begin shortly from below the last casing point and will progress to the planned total depth. The JV Partners expect the Well to be completed within the original timeframe announced on January 23, 2023 of 4 to 5 months after spudding the Well. The Well has encountered multiple oil-bearing intervals in the western channel fan complex of the northern portion of the Corentyne block in formations of Maastrichtian and Campanian ages. A comprehensive logging campaign in the Maastrichtian interval indicated the presence of medium sweet crude oil of 24.9 API. Downhole fluid analysis confirmed light sweet crude oil in the Campanian interval. Logging while drilling (LWD) and cuttings indicated the presence of hydrocarbons in the upper portion of the Santonian; fluid samples have not yet been obtained. Core samples will be attempted in the Santonian interval when drilling resumes. It is not yet certain that the hydrocarbons encountered to date in the Well are yet sufficient to underpin commercial development on the Northern portion of the Corentyne block. As drilling operations continue, the Joint Venture has revised its Well total cost estimates to approximately $175-$185 million to successfully reach the target total depth, complete the anticipated logging runs and complete the well. The increase in cost includes the delays associated with the late release of the rig by a third-party and adjusting the spud date to January 2023, and costs associated with fishing and sidetrack operations. CGX is required to fund its 32% interest, after partner carry, of approximately $11 to $15 million and is currently assessing strategies to fulfill this obligation. About CGX CGX is a Canadian-based oil and gas exploration company focused on the exploration of oil in the Guyana-Suriname Basin and the development of a deep-water port in Berbice, Guyana. NEITHER THE TORONTO STOCK EXCHANGE, TSX VENTURE EXCHANGE NOR THEIR REGULATION SERVICES PROVIDERS (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TORONTO STOCK EXCHANGE AND TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS RELEASE. Oil and Gas Definitions: "API" means the American Petroleum Institute gravity, which is a measure of how heavy or light a petroleum liquid is compared to water. API gravity is thus a measure of the relative density of a petroleum liquid and the density of water, but it is used to compare the relative densities of petroleum liquids. Cautionary and 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 CGX believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding exploration and development plans and objectives with regards to Wei-1 well are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of CGX based on information currently available to it. Forward-looking statements are subject to a number of risks and uncertainties that may cause actual results to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: the need to obtain any required regulatory approvals; the ability of the Joint Venture to successfully explore and develop offshore blocks, and to fund exploration and development and the impact thereof of unforeseen costs and expenses; changes in equity and debt markets; perceptions of the prospects and the prospects of the oil and gas industry in the countries where the Company operates or has investments; and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated May 5, 2021 or the most recent management, discussion and analysis, under the heading "Risk and Uncertainties" 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, CGX 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 CGX believes that the assumptions inherent in the cautionary and forward-looking statements applicable to it 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. For further information: Please contact Todd Durkee, Vice President, Development, CGX, (832) 300-3200, www.cgxenergy.com

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