Big oil doubles profits in blockbuster 2022

BOE Report

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Publisher’s Note: Tamarack Valley Energy will be presenting at EnerCom Dallas – The Energy Investment & ESG Conference on April 18-19, 2023. Register to attend.

CALGARY, AB, March 1, 2023 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) is pleased to announce its audited financial and operating results for the three months and year ended December 31, 2022 and the results of Tamarack’s year end independent oil and gas reserves evaluation as of December 31, 2022 (the “Reserve Report“), prepared by Tamarack’s independent qualified reserves evaluator, GLJ Ltd. (“GLJ“).

Selected reserves, financial and operating information is outlined below. Selected financial and operating information should be read with Tamarack’s audited annual consolidated financial statements and related management’s discussion and analysis for the three and twelve months ended December 31, 2022, which are available on SEDAR at www.sedar.com and on Tamarack’s website at www.tamarackvalley.ca. The Company’s Annual Information Form (AIF) for the year ended December 31, 2022  is available on SEDAR and the Company’s website.

Message to Shareholders

2022 represented a year of continued transformation and operational execution as we drove towards the goal of repositioning our business into the most profitable oil plays in North America. Tamarack completed and integrated three material Clearwater acquisitions, positioning the Company as a major producer in the Clearwater oil play. Furthermore, the divestment of two non-core assets contributed to the strategic rationalization of our asset portfolio moving forward. Together with our ongoing base asset development, our net $1.7 billion of 2022 acquisition and disposition (A&D) transactions resulted in a year over year fourth quarter production increase of 59% while also achieving an uplift in our corporate liquids weighting from 69% (Q4 2021) to 82% (Q4 2022).

2022 was a record year for financial performance with $727.1 million of adjusted funds flow⁽¹⁾ and $268.5 million of free funds flow⁽¹⁾ (excluding acquisition expenditures), which enabled the return of capital to shareholders and established a strong financial position that provided a foundation for the accretive and transformational 2022 acquisitions.  During the year, we initiated a return of capital framework with our inaugural base dividend and subsequent 50% growth of monthly dividends through the year from $0.0083/share to $0.0125/share. This increase was enabled by the highly accretive Clearwater acquisitions which strengthened the free funds flow⁽¹⁾ outlook in the corporate five-year plan.

Operational execution was an important success factor in 2022, with fourth quarter production averaging 64,344 boe/d⁽²⁾, ahead of our guidance range of 62,000-64,000 boe/d⁽²⁾, despite unexpected downtime due to the extreme cold weather in December. Capital expenditures⁽³⁾ of $125 million during the fourth quarter came in at the low end of our $125 to $135 million guidance range.

Our 2022 Reserve Report highlights the significant growth, and a shift in profitability, of our reserves, which was driven by the development of our Clearwater and Charlie Lake assets. Overall, Tamarack saw a material increase in our reserve portfolio to 242.2 MMboe and $5.0 billion⁽⁴⁾ on a total proved plus probable (TPP) basis representing a 33% and 68% increase over 2021 respectively. The year-end 2022 reserves added through acquisition exceeded our original internal reserves estimates, with the most notable increase seen for the Deltastream Energy Corp. (“Deltastream“) acquisition assets which outperformed estimates by 27% on a proved developed producing (PDP) basis and 12% on a TPP basis.

Along with the transformation of the business operations, Tamarack also underwent a significant transition in capital structure with the move away from reserve based into covenant lending and the addition of long-term fixed priced debt. As part of this transition, Tamarack was able to further demonstrate environmental, social and governance (ESG) leadership through the addition of sustainability targets on the new bond issuances (SLB) and the amended revolving facility (SLL).

2022 Financial and Operating Highlights

• Achieved fourth quarter production volumes of 64,344 boe/d⁽²⁾ and yearly production volumes of 48,283 boe/d⁽²⁾ in 2022, representing a 59% and 40% increase respectively compared to the same periods in 2021.
• Generated adjusted funds flow⁽¹⁾ of $196.7 million for the quarter ($0.36/share basic and diluted) and $727.1 million for the year ended December 31, 2022 ($1.58/share basic and $1.57/share diluted).
• Generated free funds flow⁽¹⁾, excluding acquisition expenditures, of $268.5 million and net income of $345.2 million for the year.
• Initiated a return of capital framework with our inaugural monthly base dividend and subsequent monthly dividend growth of 50% through the year. Collectively, paid or accrued $55.3 million to shareholders through dividends on Tamarack common shares, including: $0.0083/share for the first five months of 2022; $0.01/share for all dividends declared between June 15, 2022 and October 15, 2022; and $0.0125/share for all dividends declared on November 15, 2022 and after.
• Invested $125.3 million in Q4 towards exploration and development (E&D) capital expenditures, excluding acquisition expenditures, and $458.6 million during the full year 2022, which contributed to the drilling of 84 (84.0 net) Clearwater oil wells, 18 (17.2 net) Charlie Lake oil wells, 16 (16.0 net) Deltastream Clearwater oil wells, 13 (13.0 net) Viking oil wells, and two (2.0 net) West Central oil wells.
• Exited the year with $1,357 million of net debt⁽¹⁾. Tamarack will prioritize debt repayment through 2023 to enable debt reduction and advancement in the Company’s enhanced shareholder return framework.

2022 Reserve Highlights

The ongoing positive impact of Tamarack’s drilling program combined with Clearwater acquisitions contributed significantly to the reserves in 2022, further enhancing the long-term resiliency and sustainability of free funds flow⁽¹⁾ for the Company moving forward. Key highlights of the Company’s proved developed producing (PDP), total proved (TP) and total proved plus probable (TPP) reserves from the Reserve Report are highlighted below.

• Increased PDP reserves 35% to 75.7 MMboe, TP reserves 30% to 135.1 Mmboe and TPP reserves 33% to 242.2 Mmboe in 2022, relative to year-end 2021.
• Realized before-tax net present value (NPV) of reserves, discounted at 10% (NPV10), of $1.8 billion on a PDP basis, $2.9 billion on a TP basis and $5.0 billion on a TPP basis, evaluated using three independent reserve evaluators average forecast pricing and foreign exchange rates as at January 2023.
• Recognized finding and development costs (F&D), including the change in future development capital (FDC), of $20.22/boe, $31.59/boe and $37.05/boe for PDP, TP and TPP respectively, which reflects an increase in FDC, due to an increase in the number of future drilling locations and cost inflation, of $34 million, $375 million and $622 million for the respective categories. For comparative purposes, F&D costs before increases in FDC were $18.64/boe, $21.60/boe and $22.27/boe, respectively.
• Realized a 27% increase for PDP reserves and a 12% increase for TPP reserves, on the acquired Deltastream assets over the internally estimated reserves at acquisition, driven by strong base production and new drill performance in H2 2022.
• Maintained modest booking of Clearwater waterflood reserves, with only 3% of total Clearwater reserves under waterflood. TPP Reserves in the area surrounding our successful Nipisi waterflood pilot are greater than 2x the primary recovery reserve estimates.

Financial & Operating Results

Reserves Snapshot by Category

Year-Over-Year Reserves Data (Forecast Prices and Costs)

2023 Outlook

Our 2023 production and capital guidance remains unchanged with target production of 68,000-72,000 boe/d⁽⁷⁾ through exploration and development expenditures expected to range from $425 to $475 million for the year. The 2023 budget is focused on delivering long term sustainable free funds flow⁽¹⁾ across our portfolio of highly economic assets in the Charlie Lake, Clearwater and enhanced oil recovery projects to enhance return of capital to shareholders. The following table summarizes our 2023 annual guidance⁽⁷⁾.

Operations Update

Clearwater

Nipisi: Tamarack has rig released two oil wells and one multi-lateral injector to date in 2023 and expects to run a two-rig program at West Nipisi through to break up. By the end of Q1 2023, Tamarack will have commenced injection into eight new West Nipisi wells. This injection program builds on the strong waterflood pilot results at 102/13-19-076-07W5.  The producing well in the pilot, supported by three single-leg injectors, has delivered over 140 mbbls of cumulative oil production in 14 months and is currently producing over 400 bopd with 15% water cut.

Nipisi development for 2023 will focus on continued waterflood expansion across the field. Multilateral injection wells and extended reach waterflood patterns are being implemented to enhance waterflood capital efficiencies. Production for the first three weeks of February averaged 12,500 boe/d⁽¹⁰⁾ and construction of the second phase of Tamarack’s Nipisi gas conservation project is expected to be complete by the end of the first quarter.  Upon completion Tamarack anticipates having over 90% of its Nipisi solution gas conserved. In support of ongoing development, expansion of Tamarack’s 15-22-076-07W5 oil battery will commence in Q2 2023 with completion expected in Q4 2023. Volumes from this battery will be connected to a third-party pipeline where Tamarack holds an agreement for firm service. Once the battery is operational ~70% of Tamarack’s Nipisi oil production will be shipped via pipeline.

West Marten: The Company recently brought three new extended reach wells on stream at its 15-15-076-05W5 location.  The three wells were drilled under Tamarack’s West Nipisi waterflood design. The wells continue to clean up, but recent production has been over 700 bopd from the pad.  Tamarack has one drilling rig running in West Marten at the 11-10-076-05W5 pad with three oil wells rig released to date, and another six planned wells before breakup. The first two wells from the 11-10 pad site are expected to commence production in the first half of March.  West Marten production rates have averaged 1,900 boed/d⁽¹¹⁾ for the first three weeks of February and are expected to continue to climb as existing wells are optimized and new wells are brought on stream.  Tamarack is currently evaluating gas conservation in West Marten and will provide further updates throughout the year.

Marten Hills and Canal: Production from Marten Hills and Canal averaged approximately 16,300 boe/d⁽¹²⁾  over the first three weeks of February, up from approximately 15,100 boe/d⁽¹²⁾ at the close of the acquisition.  Tamarack has two drilling rigs active in Marten Hills, which are expected to remain active until spring break-up, with eight wells rig released year-to-date in 2023. Two of the eight wells are currently recovering load fluid and three additional wells are expected to start recovering load fluid in the first week of March.  Tamarack continues to evaluate waterflood in Marten Hills with additional pilots planned for later in 2023.

Southern Clearwater: Tamarack has rig released two wells year-to-date in Southern Clearwater and anticipates further drilling to commence in the second half of 2023.  Its newly drilled 07-21-063-26W4 Jarvie well is on production and exceeding expectations, with an average production rate of 220 bopd over the first nine days.  This is the first extended reach multi-lateral Tamarack has drilled in Southern Clearwater. These promising results are expected to further extend the eastern boundaries of the Jarvie pool.  Tamarack also remains encouraged by results in Perryvale, with the 09-03-064-23W4 pad site exceeding 950 bopd from seven wells, five of which have been on production for over four months, after an expansion and debottlenecking project was completed.

Charlie Lake

In the Charlie Lake, Tamarack brought on three wells  during Q4 2022.  The 1-24-072-09W6 well continues to exceed expectations and ranks as one of the top performing oil wells drilled in the play to-date. Based on field estimates, month-to-date in February, the 1-24 well averaged over 1,900 boe/d⁽¹³⁾.

Tamarack currently has three drilling rigs  active in the area and three wells are completed, awaiting final tie-in.  Two drilling rigs are expected to remain active until late Q2 2023.  Tamarack is advancing to the construction phase of the Wembley Gas Plant and is on track to be onstream at the end of Q2 2023. Current production on this asset is approximately 16,900 boe/d⁽¹⁴⁾_.

Exploration/Delineation Update

Enhancing the underlying profitability of our inventory is key to free funds flow growth and a critical component of our strategic five-year plan,. The Company had an active 2022 program and continues to move the program forward in 2023.

Clearwater

Peavine/Seal – Tamarack drilled its first multi-lateral well in Peavine, the results of which came in below expectations at approximately 40 bopd. Further appraisal of the area is planned for the second half of 2023 and 2024. At Seal, Tamarack has rig released three wells targeting three separate Clearwater equivalent sands. Testing of this three well pad is expected to commence by the end of the first quarter.

West Marten Hills Exploration – In 2022, Tamarack drilled a Clearwater C step-out well at 102/13-13-076-05W5. With initial rates of over 200 bopd, this well, along with competitor activity, has delineated over 20 sections of Clearwater C potential. Furthermore, it has provided the opportunity to optimize pad development by drilling both Clearwater C and Clearwater B sands from single pads, utilizing shared infrastructure and improving capital efficiencies.

West Nipisi – Delineation of Clearwater C and Clearwater B potential continues with partner wells at 09-05-077-09W5 (C) and 04-35-076-9W5 (B). Initial rates from the 04-35 well exceeded expectations with February month-to-date field estimates of >200 bopd. The 09-05 well is currently cleaning up. These positive results continue to expand the Clearwater potential westward.

Board of Directors Changes

Tamarack is pleased to announce the appointment of Ms. Caralyn Bennett to the Board of Directors, effective March 1, 2023. Ms. Bennett is Executive Vice President and Chief Strategy Officer of GLJ Ltd., while also serving as President of the Canadian Heavy Oil Association and as a director of Acceleware Ltd. Caralyn brings strong advisory experience in reserves and resource governance and contributes strategic expertise to business transformation including sustainability, decarbonization and energy diversification. She has a Professional Engineer designation with an Honours B.A.Sc. in Geological Engineering from the University of Waterloo and actively volunteers her strategic and advisory expertise to a variety of energy development and educational organizations in Alberta and Ontario.

Risk Management

The Company takes a systematic approach to manage commodity price risk and volatility to ensure sustaining capital, debt servicing requirements and the base dividend are protected through a prudent hedging management program. For 2023, approximately ~50% of net after royalty oil production is hedged against WTI with an average floor price of greater than US$65/bbl. Our strategy provides downside protection while maximizing upside exposure. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca).

We would like to thank our employees, shareholders and other stakeholders for all of their support over the past year. 2022 was another transformative year for Tamarack and it would not have happened without the dedication and hard work of our employees, as well as the support from our Board of Directors. We look forward to the continued development of our high-quality assets and the creation of shareholder value in a sustainable and responsible way.

2022 Independent Qualified Reserve Evaluation

The following tables highlight the findings of the Reserve Report, which has been 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 Handbook (COGEH). 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. The information included in the “Net Present Values of Future Net Revenue Before Income Taxes Discounted” table below is based on an average of pricing assumptions prepared by the following three independent external reserves evaluators: GLJ, Sproule Associates Limited and McDaniel & Associates Consultants Ltd (the “3-Consultant Average Forecast Pricing“). 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. All per share reserves metrics below are based on basic shares outstanding as of December 31, 2022.

Company Reserves Data (Forecast Prices and Costs)

Net Present Values of Future Net Revenue before Income Taxes Discounted at (% per year)⁽¹⁸⁾

Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs⁽⁵⁾

Future Development Capital Costs⁽²¹⁾

The following is a summary of GLJ’s estimated FDC required to bring TP and TPP undeveloped reserves on production.

Finding, Development & Acquisition Costs

About Tamarack Valley Energy Ltd.

Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake, Clearwater and EOR plays in Alberta. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. For more information, please visit the Company’s website at www.tamarackvalley.ca.

Abbreviations

Reader Advisories

Notes to Press Release

Disclosure of Oil and Gas Information

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 Canadian Securities Administrators’ National Instrument 51 101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Boe may be misleading, particularly if used in isolation.

References in this press release to “crude oil” or “oil” refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to “NGL” throughout this press release comprise pentane, butane, propane, and ethane, being all NGL 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.

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: Tamarack’s business strategy, objectives, strength and focus; future consolidation activity, organic growth and development and portfolio rationalization; future intentions with respect to return of capital, including enhanced dividends and share buybacks; oil and natural gas production levels, adjusted funds flow and free funds flow; anticipated operational results for 2023 including, but not limited to, estimated or anticipated production levels, capital expenditures, drilling plans and infrastructure initiatives; the Company’s capital program, guidance and budget for 2023 and 2023 capital program and the funding thereof; expectations regarding commodity prices; the performance characteristics of the Company’s oil and natural gas properties; decline rates and enhanced recovery, including waterflood initiatives; exploration activities; successful integration of the Deltastream assets; the ability of the Company to achieve drilling success consistent with management’s expectations; risk management activities, Tamarack’s commitment to ESG principles and sustainability; and the source of funding for the Company’s activities including development costs. Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the Company’s return of capital framework and the funds available for such activities from time to time is dependent upon, among other things, free funds flow financial requirements for the Company’s operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company’s control. Further, the ability of Tamarack to pay dividends and buyback shares will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility. Statements relating to “reserves” 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 Tamarack, including those relating to: the business plan of Tamarack; the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack’s properties; the characteristics of recently acquired assets, including the Deltastream assets; the successful integration of recently acquired assets into Tamarack’s operations; 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; impact of inflation on costs; 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 Tamarack’s geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack’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 Tamarack 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: the risk that future dividend payments thereunder are reduced, suspended or cancelled; unforeseen difficulties in integrating of recently acquired assets into Tamarack’s operations, including the Deltastream assets; incorrect assessments of the value of benefits to be obtained from acquisitions and exploration and development programs; 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; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; health, safety, litigation and environmental risks; access to capital; the COVID-19 pandemic; and Russia’s military actions in Ukraine. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the Company’s AIF and the management discussion and analysis for the period ended December 31, 2022 (the “MD&A“) for additional risk factors relating to Tamarack, which can be accessed either on Tamarack’s website at www.tamarackvalley.ca 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 generating sustainable long-term growth in free funds flow, dividends and share buybacks, prospective results of operations and production, weightings, operating costs, 2023 capital budget and expenditures, decline rates, balance sheet strength, adjusted funds flow and free funds flow, net debt, debt repayments, total returns and components thereof, 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 Tamarack’s future business operations. Tamarack 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. Tamarack 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 Tamarack’s guidance. The Company’s actual results may differ materially from these estimates.

Specified Financial Measures

This press release includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios and capital management measures as further described herein. These measures do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and, therefore, may not be comparable with the calculation of similar measures by other companies.

“Adjusted funds flow (capital management measure)” is calculated by taking cash-flow from operating activities, on a periodic basis, deducting current income taxes and adding back changes in non-cash working capital, expenditures on decommissioning obligations and transaction costs since Tamarack believes the timing of collection, payment or incurrence of these items is variable. While current income taxes will not be paid until Q1/23, management believes adjusting for estimated current income taxes in the period incurred is a better indication of the adjusted funds generated by the Company. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of the Company’s operating areas. Expenditures on decommissioning obligations are managed through the capital budgeting process which considers available adjusted funds flow. Tamarack uses adjusted funds flow as a key measure to demonstrate the Company’s ability to generate funds to repay debt and fund future capital investment. Adjusted funds flow per share is calculated using the same weighted average basic and diluted shares that are used in calculating income per share. Adjusted funds flow can also be calculated on a per boe basis, which results in the measure being considered a non-IFRS financial ratio.

“Free funds flow (previously referred to as “free adjusted funds flow”) and Capital Expenditures (capital management measure)“. Fee funds flow is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Capital expenditure is calculated as property, plant and equipment additions (net of government assistance) plus exploration and evaluation additions. Management believes that free funds flow provides a useful measure to determine Tamarack’s ability to improve returns and to manage the long-term value of the business.

“Net Production Expenses, Revenue, net of blending expense, Operating Netback and Operating Field Netback (Non-IFRS Financial Measures, and Non-IFRS Financial Ratios if calculated on a per boe basis)” Management uses certain industry benchmarks, such as net production expenses, revenue, net of blending expense, operating netback and operating field netback, to analyze financial and operating performance. Net production expenses are determined by deducting processing income primarily generated by processing third party volumes at processing facilities where the Company has an ownership interest. Under IFRS this source of funds is required to be reported as revenue. Blending expense includes the cost of blending diluent to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications and is shown as a reduction to heavy oil revenues rather than an expense as in the financial statements under IFRS. Operating netback equals total petroleum and natural gas sales (net of blending), including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties, net production expenses and transportation expense. Operating field netback equals total petroleum and natural gas sales, less royalties, net production expenses and transportation expense. These metrics can also be calculated on a per boe basis, which results in them being considered a non-IFRS financial ratio. Management considers operating netback and operating field netback important measures to evaluate Tamarack’s operational performance, as it demonstrates field level profitability relative to current commodity prices.  See the MD&A for a detailed calculation and reconciliation of Tamarack’s netbacks per boe to the most directly comparable measure presented in accordance with IFRS.

“Net debt (capital management measure)” is calculated as credit facilities plus senior unsecured notes, plus deferred acquisition payment notes, plus working capital surplus or deficiency, plus other liability, including the fair value of cross-currency swaps, plus government loans, plus facilities acquisition payments, less notes receivable and excluding the current portion of fair value of financial instruments, decommissioning obligations, lease liabilities and the cash award incentive plan liability.

“Net debt to quarterly annualized adjusted funds flow (capital management measure)” is calculated as estimated period end net debt divided by the annualized adjusted funds flow for the preceding quarter (multiplied by 4 for annualization).

SOURCE Tamarack Valley Energy Ltd.

FOURTH QUARTER HIGHLIGHTS Production of 78,854 Boe per day (59.5% oil), a 23% increase fr…

Oil Price

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Cheniere Energy, the biggest U.S. LNG exporter, more than doubled its revenues in 2022 from a year earlier as Europe imported increased volumes and paid high prices for gas as it sought to replace Russian pipeline supply.

 

Cheniere (NYSEAMERICAN: LNG) reported today total revenues of $33.428 billion for 2022, up from $15.864 billion for 2021. Last year’s revenues beat the analyst consensus expectation of $32.7 billion. Cheniere also reported a net profit of $1.428 billion, compared to a loss of $2.343 billion for 2021.

Europe attracted most of the U.S. exports of LNG last year as demand in Asia was weak while the EU raced to fill inventories ahead of the 2022/2023 winter. The weak demand in Asia due to China’s zero-Covid policy and high prices that south Asian LNG importers couldn’t afford helped Europe stock up ahead of this winter. Cheniere, as the top U.S. LNG exporter, benefited from the European rush to buy LNG.

“Europe had to compete for LNG cargoes resulting in unprecedented price spikes,” Cheniere said in the comments on the market environment in its SEC filing.

“This extreme price increase triggered a strong supply response from the U.S., which played a significant role in balancing the global LNG market. Despite the outage at Freeport LNG, the U.S. exported approximately 77 million tonnes of LNG in 2022, a gain of approximately 9% from 2021, as the market continued to pull on supplies from our facilities and those of our competitors,” the U.S. LNG exporter said.

Cheniere believes it is well positioned to help meet the increased demand of its international LNG customers to overcome their supply shortages, it said.

U.S. exports could rise later this year after Freeport LNG, the second-largest U.S. LNG export facility, earlier this week received regulatory approval to resume commercial operations of its natural gas liquefaction and export facility.

By Tsvetana Paraskova for Oilprice.com

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Oil and Gas 360

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DENVER, Feb. 22, 2023 /PRNewswire/ — SM Energy Company (the “Company”) (NYSE: SM) today announced certain fourth quarter and full year 2022 operating and financial results, year-end 2022 estimated proved reserves and its 2023 operating plan. Highlights include:

 

• Substantial growth in profitability. Net income for the full year 2022 and fourth quarter 2022 was $1.11 billion and $258.5 million, or $8.96 and $2.09 per diluted common share, respectively. Adjusted net income⁽¹⁾ for the full year 2022 and fourth quarter 2022 was $7.29 and $1.29 per diluted common share, respectively.
• Increased return of capital to stockholders through share buybacks and fixed dividend. The Company repurchased 1,365,255 shares from announcement of its return of capital program on September 7, 2022 through year-end and initiated payment of the $0.15 quarterly dividend on November 7, 2022.
• Proved reserves growth. Estimated proved reserves at year-end 2022 totaled 537 MMBoe, a 9% increase from year-end 2021, replacing 2022 production by 205%. The ratio of estimated proved reserves at year-end 2022 to 2022 production is 10.1 years. The standardized measure of discounted future net cash flows from estimated proved reserves was $9.96 billion, up 43% from year-end 2021.
• Significant cash flow generation. For the full year 2022, net cash provided by operating activities of $1.69 billion before net change in working capital of $72.1 million totaled $1.76 billion.⁽¹⁾ Fourth quarter net cash provided by operating activities of $288.4 million before net change in working capital of $58.8 million was $347.2 million.⁽¹⁾ For the full year 2022, the Company generated Adjusted free cash flow⁽¹⁾ of $848.7 million, more than double the Adjusted free cash flow generated in 2021.
• Production at high end of guidance. Production for the full year 2022 was 53.0 MMBoe or 145.1 MBoe/d, up 3% from 2021. Fourth quarter production was 13.1 MMBoe or 142.9 MBoe/d.
• Strengthened balance sheet. Cash and cash equivalents at year-end 2022 were $445.0 million. Utilizing cash generated in 2022, and in support of the Company’s objective to reduce absolute debt, the Company redeemed $551.4 million of long-term debt and ended 2022 with a net debt-to-Adjusted EBITDAX⁽¹⁾ ratio of 0.59 times.
• Stewardship targets on track. The Company made substantial progress in 2022 and is committed to achieving its short-to-medium-term targets for flaring, Scope 1 and 2 greenhouse gas emissions reductions, and methane intensity. For full year 2022, the Company had de minimis routine flaring and non-routine flaring was less than 1% at all SM Energy operations. Scope 1 and 2 greenhouse gas emissions intensity was down an estimated 40% from base year 2019 and methane intensity was estimated at less than 0.04 mT CH4/MBoe.

2023 Strategic Objectives:

• Deliver increased return of capital to stockholders. Continue the Company’s sustainable capital return program through the increased fixed annual dividend of $0.60 per share, to be paid in quarterly increments, and share repurchases of up to $500.0 million in total through 2024, while maintaining a strong balance sheet.
• Focus on operational execution. Optimize capital efficiency, demonstrate innovation and maintain focus on ESG stewardship.
• Continue to replace/build top-tier inventory. Repeat the Company’s track record of inventory replacement and growth, applying the Company’s differential strength in geosciences and development optimization.

Chief Executive Officer Herb Vogel comments: “We are very pleased to report our results and achievements for 2022, which exceeded our strategic objectives. We generated Adjusted free cash flow⁽¹⁾ of $848.7 million, a 20% yield to market capitalization⁽¹⁾ at year-end. We outperformed our leverage objective and initiated a capital return program via an increased dividend and share repurchases. Proved reserves increased to 537 million Boe, which resulted in a Pre-tax PV-10⁽¹⁾ value of $12.15 billion and demonstrated our high-quality asset base. Our strategy is to be a premier operator of top tier assets and our 2023 objectives are intended to drive value creation, differential performance and increased stockholder returns.”

Estimated proved reserves at year-end 2022 were 537 MMBoe. Estimated proved reserves were 52% in South Texas and 48% in the Midland Basin, and were comprised of 38% oil, 44% natural gas and 18% NGLs. Reserves were 59% proved developed and 41% proved undeveloped.

• The ratio of estimated proved reserves at year-end 2022 to 2022 production is 10.1 years.
• Proved reserve additions and revisions related to infill and performance were 108.8 MMBoe, replacing 2022 production by 205%.
• 2022 SEC pricing was $93.67 per Bbl oil, $6.36 per Mcf natural gas and $42.52 per Bbl NGLs, up 41%, 77% and 16%, respectively, compared to 2021 SEC pricing.
• The nominal increase in proved reserves due to price revisions is a testament to the high-quality and commodity price resiliency of the Company’s reserve base.
• South Texas proved reserves increased 40 MMBoe compared with 2021 as a result of continued Austin Chalk success.
• PDP reserves of 308 MMBoe surpassed the Company’s previous peak of 297 MMBoe, set at the end of 2021.

STANDARDIZED MEASURE

The standardized measure of discounted future net cash flows from estimated proved reserves was $9.96 billion at year-end 2022, up from $6.96 billion at year-end 2021. The 43% increase in the standardized measure compared with year-end 2021 is predominantly due to the increase in reserves and SEC pricing across commodities used in the calculation. Pre-tax PV-10⁽¹⁾ was $12.15 billion, the highest value in Company history.

• Fourth quarter production volumes of 13.1 MMBoe (142.9 MBoe/d) were up 4% sequentially, near the high end of guidance, and were 43% oil.
• Fourth quarter volumes in South Texas reflect approximately 0.08 MMBoe shut-in due to inclement weather in December. South Texas infrastructure was designed as a dry gas system supporting Eagle Ford production and the Company experiences intermittent curtailments at certain wells due to high line pressures associated with the high liquids content of Austin Chalk wells. During the fourth quarter 2022, the effect of high line pressures curtailed an estimated 0.2 MMBoe of production, which was largely considered in guidance. The Company continues to work with its midstream partners to upgrade facilities in the region to accommodate the higher liquids production.

• Full year production volumes of 53.0 MMBoe (145.1 MBoe/d) were up 3% from 2021.
• Production volumes were 56% from the Midland Basin and 44% from South Texas. Volumes were 45% oil, 15% NGLs and 40% natural gas.
• Oil volumes from South Texas reflect a 78% increase over the prior year period as the Company continued delineation drilling and initiated development drilling of the Austin Chalk on its 155,000-acre South Texas position.

 

• In the fourth quarter, the average realized price before the effect of hedges was $50.92 per Boe and the average realized price after the effect of hedges was $42.12 per Boe.⁽¹⁾ For the full year, the average realized price before the effect of hedges was $63.18 per Boe and the average realized price after the effect of hedges was $49.76 per Boe.⁽¹⁾ 
• In the fourth quarter, benchmark pricing included NYMEX WTI at $82.64/Bbl, NYMEX Henry Hub natural gas at $6.26/MMBtu and Hart Composite NGLs at $33.03/Bbl. For the full year, benchmark pricing included NYMEX WTI at $94.23/Bbl, NYMEX Henry Hub natural gas at $6.64/MMBtu and Hart Composite NGLs at $43.48/Bbl.
• The effect of commodity derivative settlements for the fourth quarter and full year was a loss of $8.80 per Boe, or $115.6 million, and a loss of $13.42 per Boe, or $710.7 million, respectively.

For additional operating metrics and regional detail, please see the Financial Highlights section below and the accompanying slide deck.

NET INCOME, NET INCOME PER SHARE AND NET CASH PROVIDED BY OPERATING ACTIVITIES

Fourth quarter 2022 net income was $258.5 million, or $2.09 per diluted common share, compared with net income of $424.9 million, or $3.43 per diluted common share, for the same period in 2021. The current year period included a 21% decrease in operating revenues and other income, compared with the same period in 2021, due to lower production partially offset by higher realized prices for oil and NGLs after the effect of derivative settlements, as well as increased production costs. For the full year 2022, net income was $1.11 billion, or $8.96 per diluted common share, compared with net income of $36.2 million, or $0.29 per diluted common share, for the full year 2021. Full year net income reflects a 28% increase in operating revenues and other income, a 22% decrease in DD&A expense, and lower net derivative loss, which was partially offset by higher production expenses per Boe and higher income tax expense.

Fourth quarter 2022 net cash provided by operating activities of $288.4 million before net change in working capital of $58.8 million totaled $347.2 million,⁽¹⁾ which was down $17.2 million, or 5%, from $364.4 million⁽¹⁾ in the same period in 2021. For the full year 2022, net cash provided by operating activities of $1.69 billion before net changes in working capital of $72.1 million totaled $1.76 billion,⁽¹⁾ which was up $716.1 million, or 69%, from $1.04 billion⁽¹⁾ in 2021.

ADJUSTED EBITDAX,⁽¹⁾ ADJUSTED NET INCOME⁽¹⁾ AND NET DEBT-TO-ADJUSTED EBITDAX⁽¹⁾

Fourth quarter 2022 Adjusted EBITDAX⁽¹⁾ was $373.9 million, down $33.0 million, or 8%, from $406.9 million in the same period in 2021. The decrease in Adjusted EBITDAX⁽¹⁾ was due to lower production and higher production costs per Boe, partially offset by a higher realized price per Boe after the effect of derivative settlements. For the full year 2022, Adjusted EBITDAX⁽¹⁾ was $1.92 billion, compared with $1.23 billion in 2021. The 57% increase in Adjusted EBITDAX was due to a 3% increase in production, 38% increase in the average realized price per Boe after the effect of derivative settlements, and lower cash interest expense, which was partially offset by higher production costs per Boe.

Fourth quarter 2022 adjusted net income⁽¹⁾ was $159.2 million, or $1.29 per diluted common share, which compares with adjusted net income⁽¹⁾ of $141.5 million, or $1.14 per diluted common share, for the same period in 2021. For the full year 2022, adjusted net income⁽¹⁾ was $904.0 million, or $7.29 per diluted common share, compared with adjusted net income⁽¹⁾ of $228.3 million, or $1.85 per diluted common share, in 2021.

At December 31, 2022, Net debt-to-Adjusted EBITDAX⁽¹⁾ was 0.59 times.

FINANCIAL POSITION, LIQUIDITY AND CAPITAL EXPENDITURES

At year-end 2022, the outstanding principal amount of the Company’s long-term debt was $1.59 billion with zero drawn on the Company’s senior secured revolving credit facility. At year-end 2022, cash and cash equivalents were $445.0 million and net debt⁽¹⁾ was $1.14 billion, down $663.7 million from year-end 2021. As of December 31, 2022, the Company’s borrowing base and commitments under its senior secured revolving credit facility were $2.50 billion and $1.25 billion, respectively, providing $1.70 billion in available liquidity.

In the fourth quarter 2022, capital expenditures of $288.1 million adjusted for decreased capital accruals of $20.8 million were $267.3 million.⁽¹⁾ During the fourth quarter of 2022, the Company drilled 26 net wells and added 21 net flowing completions. For the full year 2022, capital expenditures of $879.9 million adjusted for increased capital accruals of $29.8 million totaled $909.7 million⁽¹⁾ and the Company drilled 90 net wells and added 79 net flowing completions. Fourth quarter and full year capital expenditures adjusted for capital accruals exceeded guidance by approximately $10 million primarily due to the unplanned pre-purchase of pipe for 2023 activity.

Commodity hedge positions as of February 15, 2023:

• Oil: Slightly less than 30% of expected 2023 oil production is hedged to contract prices in the Midland Basin at an average price of $74.10/Bbl (weighted-average of collar floors and swaps, excludes basis swaps).
• Oil, Midland Basin differential: Approximately 5,400 MBbls is hedged to the local price point at a positive $0.94/Bbl basis.
• Natural gas: Slightly less than 30% of expected 2023 natural gas production is hedged at an average price of $3.97/MMBtu (weighted-average of collar floors and swaps, excludes basis swaps).

A detailed schedule of these and other hedge positions are provided in the accompanying slide deck.

Discussion in this release of the Company’s 2023 operating plan guidance includes the term “capital expenditures,” which is defined to include adjustments for capital accruals, and is a non-GAAP measure. In reliance on the exception provided by Item 10(e)(1)(i)(B) of Regulation S-K, the Company is unable to provide a reconciliation of forward-looking non-GAAP capital expenditures because components of the calculations are inherently unpredictable, such as changes to, and the timing of, capital accruals, unknown future events, and estimating certain future GAAP measures. The inability to project certain components of the calculation could significantly affect the accuracy of a reconciliation.

KEY ASSUMPTIONS

• Price deck approximates early February strip prices at $80.00 per Bbl WTI; $3.00 per MMBtu natural gas; $34.00 per Bbl NGLs.
• Hedges currently in place.
• Processing ethane for the full year.

GUIDANCE FULL YEAR 2023:

• Production volumes year-over-year are expected to remain flat to low single digit growth at 52.5-54.5 MMBoe, or 144-150 MBoe/d at 43% oil.
• Capital expenditures adjusted for capital accruals⁽¹⁾: are expected to be approximately $1.1 billion, excluding acquisitions.
  • The capital program increased the allocation to Midland Basin activity due to the expectation of lower natural gas prices in 2023. The allocation of drilling and completion capital is expected to be roughly 60% to the Midland Basin and 40% to South Texas.
  • The capital program includes approximately $45 million for facilities, including extension of the South Texas oil facilities, as well as $22 million for capitalized interest.
  • Total net wells drilled is expected to approximate 85-90, roughly split equally between Midland Basin and South Texas. Total net wells completed is expected to approximate 50 in Midland Basin and 40 in South Texas.
    • Midland Basin operations are expected to continue to co-develop zones and is expected to include activity across the RockStar position as well as in Sweetie Peck. The scheduling of the Guitar consolidated development, a previously discussed project that includes 20 wells on four adjacent pads, has been modified with all wells completed by the end of the second quarter and turned-in-line by early in the third quarter.
    • South Texas activity is expected to be concentrated on Austin Chalk development.
• Production costs:
  • LOE is expected to average between $5.75-6.00/Boe, which includes workover activity;
  • Transportation is expected to approximate $2.50/Boe, which includes a reduction to South Texas natural gas transportation costs of approximately $0.35/Mcf starting in July 2023;
  • Production and ad valorem taxes are expected to average between $2.90-3.00/Boe.
• G&A: is expected to approximate $120 million.
• Exploration/Capitalized overhead: is expected to approximate $45 million.
• DD&A: is expected to average between $12-13/Boe.

GUIDANCE FIRST QUARTER 2023:

• Capital expenditures: are expected to range between $320-330 million, which includes drilling approximately 22 net wells, completing approximately 25 net wells and facilities costs. Capital expenditures are weighted to the first half of the year, which includes approximately 60% of 2023 well completions and facilities costs.
• Production: is expected to range between 12.9-13.1 MMBoe, or 143-146 MBoe/d, at 42-43% oil. Production volumes consider the expected effects of offset activity and curtailments.

EARNINGS Q&A WEBCAST AND CONFERENCE CALL

February 23, 2023 – Please join SM Energy management at 8:00 a.m. Mountain time/10:00 a.m. Eastern time for the 2022 financial and operating results/2023 operating plan Q&A session. This discussion will be accessible via webcast (available live and for replay) on the Company’s website at ir.sm-energy.com or by telephone. In order to join the live conference call, please register at the link below for dial-in information.

• Live Conference Call Registration: https://conferencingportals.com/event/pAjDSntN
• Replay (conference ID 11299) – Domestic toll free/International: 888-330-2434/240-789-2725

The call replay will be available approximately one hour after the call and until March 9, 2023.

CONFERENCE PARTICIPATION

• February 27, 2023 – Credit Suisse 28^th Annual Vail Summit. Executive Vice President and Chief Financial Officer Wade Pursell will present at 9:15 a.m. Mountain time and will participate in investor meetings at the event. The presentation will be webcast, accessible from the Company’s website and available for replay for a limited time.
• March 6, 2023 – J.P. Morgan 2023 Global High Yield & Leveraged Finance Conference. Executive Vice President and Chief Financial Officer Wade Pursell will participate in investor meetings at the event.

FORWARD LOOKING STATEMENTS

This release contains forward-looking statements within the meaning of securities laws. The words “deliver,” “demonstrate,” “establish,” “estimate,” “expects,” “goal,” “generate,” “maintain,” “objectives,” “optimize,” “target,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this release include, among other things, commodity prices, projections for the first quarter and full year 2023 regarding guidance for capital, production, operating costs, general and administrative expenses, exploration expenses and DD&A and the number of net wells to be drilled and completed; the allocation of activity between our operating areas and, the Company’s 2023 strategic objectives, including generating and applying free cash flow to capital returns, maintaining low leverage, optimizing capital efficiency, replacing inventory and meeting the Company’s ESG stewardship goals. These statements involve known and unknown risks, which may cause SM Energy’s actual results to differ materially from results expressed or implied by the forward-looking statements. Future results may be impacted by the risks discussed in the Risk Factors section of SM Energy’s most recent Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company’s other periodic reports filed with the Securities and Exchange Commission, specifically the 2022 Form 10-K. The forward-looking statements contained herein speak as of the date of this release. Although SM Energy may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so, except as required by securities laws.

RESERVE DISCLOSURE

The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose estimated proved reserves, which are those quantities of oil, natural gas and NGLs, that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs and under existing economic conditions (using the trailing 12-month average first-day-of-the-month prices), operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, the Company currently does not disclose probable or possible reserves in its SEC filings.

Estimated proved reserves attributable to the Company at December 31, 2022, are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $93.67 per Bbl of oil, $6.36 per MMBtu of natural gas, and $42.52 per Bbl of NGLs. At least 80% of the PV-10 of the Company’s estimate of its total estimated proved reserves as of December 31, 2022, was audited by Ryder Scott Company, L.P.

FOOTNOTE 1: Indicates a non-GAAP measure or metric. Please refer to the “Definitions of non-GAAP Measures and Metrics as Calculated by the Company” section in Financial Highlights for additional information.

SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at www.sm-energy.com.

Jennifer Martin Samuels, jsamuels@sm-energy.com, 303-864-2507

 

 

 

 

 

To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), the Company provides certain non-GAAP measures and metrics, which are used by management and the investment community to assess the Company’s financial condition, results of operations, and cash flows, as well as compare performance from period to period and across the Company’s peer group. The Company believes these measures and metrics are widely used by the investment community, including investors, research analysts and others, to evaluate and compare recurring financial results among upstream oil and gas companies in making investment decisions or recommendations. These measures and metrics, as presented, may have differing calculations among companies and investment professionals and may not be directly comparable to the same measures and metrics provided by others. A non-GAAP measure should not be considered in isolation or as a substitute for the most directly comparable GAAP measure or any other measure of a company’s financial or operating performance presented in accordance with GAAP. A reconciliation of the Company’s non-GAAP measures to the most directly comparable GAAP measure is presented below. These measures may not be comparable to similarly titled measures of other companies.

Adjusted EBITDAX : Adjusted EBITDAX is calculated as net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. The Company believes that Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to financial covenants under the Company’s Credit Agreement, a material source of liquidity for the Company, based on Adjusted EBITDAX ratios. Please reference the Company’s 2022 Form 10-K for discussion of the Credit Agreement and its covenants.

Adjusted net income (loss) and adjusted net income (loss) per diluted common share : Adjusted net income (loss) and adjusted net income (loss) per diluted common share excludes certain items that the Company believes affect the comparability of operating results, including items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as derivative gains and losses net of settlements, impairments, net (gain) loss on divestiture activity, gains and losses on extinguishment of debt, and accruals for non-recurring matters. The Company uses these measures to evaluate the comparability of the Company’s ongoing operational results and trends and believes these measures provide useful information to investors for analysis of the Company’s fundamental business on a recurring basis.

Adjusted free cash flow : Adjusted free cash flow is calculated as net cash provided by operating activities before net change in working capital less capital expenditures before increase (decrease) in capital expenditure accruals and other. The Company uses this measure as representative of the cash from operations, in excess of capital expenditures that provides liquidity to fund discretionary obligations such as debt reduction, returning cash to stockholders or expanding the business.

Adjusted free cash flow yield to market capitalization :  Adjusted free cash flow yield to market capitalization is calculated as Adjusted free cash flow (defined above) divided by market capitalization (share close price multiplied by outstanding common stock). The Company believes this metric provides useful information to management and investors as a measure of the Company’s ability to internally fund its capital expenditures, to service or incur additional debt, and to measure management’s success in creating stockholder value.

Net debt : Net debt is calculated as the total principal amount of outstanding senior unsecured notes plus amounts drawn on the revolving credit facility less cash and cash equivalents (also referred to as total funded debt). The Company uses net debt as a measure of financial position and believes this measure provides useful additional information to investors to evaluate the Company’s capital structure and financial leverage.

Net debt-to-Adjusted EBITDAX : Net debt-to-Adjusted EBITDAX is calculated as Net Debt (defined above) divided by Adjusted EBITDAX (defined above) for the trailing twelve-month period (also referred to as leverage ratio). A variation of this calculation is a financial covenant under the Company’s Credit Agreement. The Company and the investment community may use this metric in understanding the Company’s ability to service its debt and identify trends in its leverage position. The Company reconciles the two non-GAAP measure components of this calculation.

Pre-Tax PV-10 : Pre-Tax PV-10 is the present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This measure is presented because management believes it provides useful information to investors for analysis of the Company’s fundamental business on a recurring basis.

Reinvestment rate : Reinvestment rate is calculated as capital expenditures before increase (decrease) in capital expenditure accruals and other divided by net cash provided by operating activities before net change in working capital. The Company believes this metric is useful to management and the investment community to understand the Company’s ability to generate sustainable profitability and may be used to compare over periods of time across industry peers.

Post-hedge:  Post-hedge is calculated as the average realized price after the effects of commodity derivative settlements. The Company believes this metric is useful to management and the investment community to understand the effects of commodity derivative settlements on average realized price.

 

 

 

 

 

 

 

SOURCE SM Energy Company