February 13, 2020 - 6:00 AM EST
Print Email Article Font Down Font Up
Precision Drilling Corporation Announces 2019 Fourth Quarter and Year End Unaudited Financial Results

CALGARY, Alberta, Feb. 13, 2020 (GLOBE NEWSWIRE) -- (Canadian dollars except as indicated)

This news release contains “forward-looking information and statements” within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the “Cautionary Statement Regarding Forward-Looking Information and Statements” later in this news release. This news release contains references to Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see “Non-GAAP Measures” later in this news release.

Precision Drilling announces 2019 fourth quarter and year end highlights:

  • Revenue of $372 million was a decrease of 13% compared with the fourth quarter of 2018.
  • Net loss of $1 million or $0.00 per diluted share compared to a net loss of $198 million or $0.68 per diluted share in the fourth quarter of 2018. Our 2019 earnings per diluted share were $0.02, compared with a net loss of $1.00 per diluted share in 2018. In the quarter we decommissioned certain drilling and ancillary equipment that no longer met our High-Performance technology standards for a loss on asset decommissioning of $20 million that, after-tax, increased our net loss by $15 million and net loss per diluted share by $0.05. During the fourth quarter of 2018, we incurred goodwill impairment charges that, after-tax, reduced net earnings by $199 million or net earnings per diluted share by $0.68.
  • Earnings before income taxes, gain on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, reversal of impairment of property, plant and equipment, loss on asset decommissioning, gain on asset disposals and depreciation and amortization (Adjusted EBITDA, see “NON-GAAP MEASURES”) of $105 million was 22% lower than the fourth quarter of 2018.
  • Funds provided by operations (see “NON-GAAP MEASURES”) was $76 million versus $93 million in the prior year quarter. Cash provided by operations was $75 million versus $93 million in the prior year quarter. The decrease in funds and cash provided by operations was primarily the result of lower activity and the non-recurring transaction termination fee that was received in the fourth quarter of 2018.
  • During the quarter we reduced our debt by $59 million bringing our 2019 debt reduction total to $205 million with an additional US$25 million of our 6.5% unsecured seniors notes due 2021 redeemed subsequent to year end. Our 2019 debt repayments are expected to reduce our 2020 interest expense by US$10 million.
  • Capital expenditures were $22 million in the fourth quarter, $8 million lower than the prior year quarter and consisted of opportunistic deployment of capital on long-lead items, pull-forward spend on certain maintenance capital and $2 million of capitalized recertification costs.
  • Pursuant to our Normal Course Issuer Bid, we purchased and cancelled 16 million common shares for $26 million in 2019. Subsequent to December 31, 2019, we purchased and cancelled an additional 2 million common shares for $3 million, leaving us with 275 million common shares outstanding at February 12, 2020.
  • Our 2019 Adjusted EBITDA from our Contract Drilling Services and Completion and Production Services segments were $429 million and $24 million, respectively, representing a 4% and 62% increase from 2018.
  • We commercialized our AlphaAutomation technology offering with our 32 field-deployed systems earning commercial rates, drilling approximately 613 wells in 2019, an increase of 69% over the prior year.

Precision’s President and CEO Kevin Neveu stated: “During the fourth quarter, Precision’s strong financial results were led by rising Canadian activity in our Contract Drilling Services and Completion and Production Services segments, firm international activity, and flattening customer demand in the U.S. As a result of Precision’s High Performance, High Value strategy, market positioning in key basins, commercialization of AlphaAutomation, intense cost control and cash management efforts, we generated Adjusted EBITDA of $105 million and cash provided by operations of $75 million. Results delivered this quarter demonstrate Precision’s ability to consistently generate cash, reduce debt and repurchase shares.”

“In Canada, Precision maintained its record level market share, supported by leading market positions in the Montney, Duvernay and heavy oil regions. Our 26 AC Super Triples and over 60 Super Singles provide Precision an unmatched scale efficiency and competitive advantage throughout all key regions in the Western Canadian market. This momentum has continued into the first quarter of 2020, as seasonal customer demand has remained strong well into February. The Company reached a peak of 83 active rigs in January, compared with a peak of 62, up 34% from the first quarter of 2019 and has 80 rigs running today compared to 55 this time last year. Although longer-term Canadian demand will be driven by customer capital discipline and commodity prices, we expect our market positioning and scale in our Canadian Drilling segment to continue to generate strong cash flows throughout the course of the year.”

“In the U.S., Precision’s fourth quarter average rig count was in-line with our expectations and generated sequentially improved margins supported by firm day rates and aggressive cost management. Our rig count ended the year softer than anticipated, due to a large customer reducing operations and idling three contracted AC ST-1500’s. Precision remains confident in its ability to redeploy these rigs as the oil and gas operators continue to high grade drilling operations in 2020. We anticipate capital discipline, operating efficiency and industrial scale will remain central themes in the U.S. market and customer spending behavior will be largely defined by remaining within cash flow and maximizing drilling efficiencies. These market trends align well with Precision’s High Performance, High Value strategy, our Alpha technologies offering and our ability to deliver industrial efficiencies to our customers.”

“Internationally, the business remains a stable source of cash generation. Looking to 2020, Precision will continue to leverage its expanded scale in Kuwait and will prioritize reactivating idle assets in the Middle East region.”

“Precision’s Completion and Production Services segment finished the year on firm footing, generating strong free cash flow, improved margins and good progress on both pricing and market share despite a highly fractured market. Our team has focused and delivered on effectively managing all elements within their control including reducing fixed and variable costs, strong operational performance, training and crewing rigs and ensuring the integrity of the assets, all while continuing to effectively manage customer relationships. We expect customer spending in 2020 will largely be tied to the commodity macro and our scale and operational efficiency will continue to support free cash flow generation in the current environment.” 

“Precision delivered on its 2019 strategic priorities established at the beginning of the year. First, the Company generated substantial free cash flow, allowing us to exceed our annual debt repayment targets for the second consecutive year by paying down $205 million of debt. Since the beginning of 2018, Precision has reduced its debt levels by $412 million, already eclipsing the low end of our four-year targeted debt reduction range of $400 million to $600 million by end of year 2021. For 2020, we plan to reduce debt by $100 million to $150 million and are now providing guidance for an additional year with a goal to reduce debt by $700 million between 2018 and 2022. Second, Precision continued to leverage its scale and High-Performance Super Series fleet to drive both strong operating margins and market share gains in the U.S. and Canada. Finally, the Company delivered on its technology initiatives for the year, achieving full commercialization of our AlphaAutomation system.” 

“Achieving our AlphaAutomation commercialization milestone was a result of three years of field-hardening the technology with over 1,100 wells drilled to date, extensive training of over 100 crews and close collaboration with our customers to demonstrate the efficiency and value this technology delivers. Looking to 2020, we plan to deploy an additional 24 AlphaAutomation systems, driven by continued customer demand to maximize drilling efficiencies. Additionally, Precision remains focused on commercializing 15 or more AlphaApps, which will further expand our portfolio of technology offerings,” concluded Mr. Neveu.

IMPACT OF IFRS 16 - LEASES ON FINANCIAL INFORMATION

On January 1, 2019, Precision applied IFRS 16 using the modified retrospective approach under which comparative information has not been restated and continues to be reported under IAS 17 and related interpretations. Please refer to “CHANGES IN ACCOUNTING POLICY” for additional information on the impact to our financial information.

SELECT FINANCIAL AND OPERATING INFORMATION

Financial Highlights

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands of Canadian dollars, except per share amounts)2019  2018  % Change  2019  2018  % Change 
Revenue 372,301   427,010   (12.8)  1,541,320   1,541,189   0.0 
Adjusted EBITDA (1) 105,006   134,492   (21.9)  391,905   375,131   4.5 
Operating earnings (loss)(1) 7,699   (172,093)  (104.5)  94,577   (198,073)  (147.7)
Net earnings (loss) (1,061)  (198,328)  (99.5)  6,618   (294,270)  (102.2)
Cash provided by operations 74,981   93,489   (19.8)  288,159   293,334   (1.8)
Funds provided by operations(1) 75,779   92,595   (18.2)  292,652   311,214   (6.0)
Capital spending:                       
Expansion 7,916   9,064   (12.7)  108,064   35,444   204.9 
Upgrade 199   2,402   (91.7)  12,846   30,757   (58.2)
Maintenance and infrastructure 13,426   18,128   (25.9)  38,976   48,375   (19.4)
Intangibles 332   687   (51.7)  808   11,567   (93.0)
Proceeds on sale (4,931)  (12,020)  (51.1)  (90,768)  (24,457)  275.0 
Net capital spending 16,942   18,261   (12.4)  69,926   101,686   (32.2)
Net earnings (loss) per share:                       
Basic (0.00)  (0.68)  (99.4)  0.02   (1.00)  (102.3)
Diluted (0.00)  (0.68)  (99.4)  0.02   (1.00)  (102.2)

 (1)     See “NON-GAAP MEASURES”.

Operating Highlights

 Three months ended December 31,  Year ended December 31, 
 2019  2018  % Change  2019  2018  % Change 
Contract drilling rig fleet 226   236   (4.2)  226   236   (4.2)
Drilling rig utilization days:                       
U.S. 5,814   7,318   (20.6)  26,544   26,714   (0.6)
Canada 3,919   4,517   (13.2)  14,498   18,617   (22.1)
International 818   736   11.1   3,093   2,920   5.9 
Revenue per utilization day:                       
U.S.(1) (US$) 23,949   23,369   2.5   23,397   21,864   7.0 
Canada (Cdn$) 22,182   22,802   (2.7)  21,569   21,644   (0.3)
International (US$) 52,283   51,982   0.6   51,360   50,469   1.8 
Operating cost per utilization day:                       
U.S. (US$) 14,073   15,042   (6.4)  14,447   14,337   0.8 
Canada (Cdn$) 14,791   15,115   (2.1)  15,240   14,493   5.2 
Service rig fleet(2) 123   210   (41.4)  123   210   (41.4)
Service rig operating hours 39,865   35,773   11.4   147,154   157,467   (6.5)
Revenue per operating hour (Cdn$) 746   753   (0.9)  739   709   4.2 

(1)     Includes revenue from idle but contracted rig days.
(2)     In 2019, 75 rigs were not registered with the industry association and 12 snubbing units were sold.

Financial Position

 (Stated in thousands of Canadian dollars, except ratios)December 31, 2019  December 31, 2018 
Working capital(1) 201,696   240,539 
Cash 74,701   96,626 
Long-term debt 1,427,181   1,706,253 
Total long-term financial liabilities 1,500,950   1,723,350 
Total assets 3,269,840   3,636,043 
Long-term debt to long-term debt plus equity ratio 0.48   0.52 

 (1)     See “NON-GAAP MEASURES”.

Summary for the three months ended December 31, 2019:

  • Revenue was $372 million, 13% lower than the fourth quarter of 2018. Revenue decreased due to lower activity in the U.S. and Canada, partially offset by higher average day rates in the U.S. and higher international activity. Compared with the fourth quarter of 2018, our drilling activity decreased 21% in the U.S., 13% in Canada and grew 11% internationally. Our 2019 fourth quarter revenue from our Contract Drilling Services and Completion and Production Services segments decreased 14% and 5%, respectively, from the comparable 2018 quarter.
  • General and administrative expenses were $26 million, $4 million higher than the fourth quarter of 2018. Excluding the effect of share-based incentive compensation expense for the quarter, our general and administrative expenses decreased by $8 million from 2018. The lower expenses in the current quarter were primarily the result of continued fixed cost control initiatives and the impact of lease-related charges due to the adoption of IFRS 16. See discussion on share-based incentive compensation under “Other Items” later in this release for additional details.
  • Adjusted EBITDA (see “NON-GAAP MEASURES”) was $105 million, a decrease of $29 million from the fourth quarter of 2018. Our Adjusted EBITDA as a percentage of revenue was 28% this quarter, compared with 31% in the comparative quarter of 2018. Operating earnings (see “NON-GAAP MEASURES”) were $8 million compared with negative $172 million in the fourth quarter of 2018. Lower Adjusted EBITDA and operating earnings in 2019 were primarily due to reduced U.S. and Canadian activity, higher share-based incentive compensation expense and the non-recurring receipt of the transaction termination fee in the fourth quarter of 2018. In the 2019 quarter, we decommissioned 29 drilling rigs resulting in a loss on asset decommissioning of $20 million. With the adoption of IFRS 16, lease-related charges of $3 million in the quarter were recognized through finance charges and depreciation and amortization expense. Historically, these charges were reflected in operating and general and administrative expense. Total share-based incentive compensation expense for the quarter was $7 million compared with a recovery of $12 million in the fourth quarter of 2018. See discussion on rig decommissioning and share-based incentive compensation under “Other Items” for additional details.
  • Net finance charges were $28 million, a decrease of $4 million compared with the fourth quarter of 2018, primarily due to a reduction in interest expense related to retired debt, partially offset by $1 million of lease accretion charges resulting from the adoption of IFRS 16.
  • Revenue per utilization day in the U.S. increased in the fourth quarter of 2019 to US$23,949 from US$23,369 in the prior year quarter. The increase was the result of higher day rates, idle but contracted rig revenue and rig technology revenue, partially offset by lower turnkey activity. During the quarter, we had US$3 million of revenue from each of idle but contracted rigs and turnkey projects as compared with fourth quarter 2018 idle but contracted rig and turnkey revenue of US$0.3 million and US$11 million, respectively. On a sequential basis, revenue per utilization day, excluding revenue from turnkey and idle but contracted rigs, was consistent with the third quarter of 2019. Operating costs on a per day basis decreased to US$14,073 in the fourth quarter of 2019 compared with US$15,042 in 2018. The decrease was mainly due to lower turnkey activity, the impact from the reversal of prior period provisions and the componentization of rig recertification costs. Excluding the impact of the provision reversals and componentization of recertification costs, our operating costs on a per day basis for the quarter were US$14,974. See discussion on change of rig components under “Other Items” for additional details
  • In Canada, average revenue per utilization day for contract drilling rigs was $22,182 compared with $22,802 in the fourth quarter of 2018. The lower average revenue per utilization day in the fourth quarter of 2019 was primarily due to lower rates from a higher proportion of Super Singles in our rig mix and lower shortfall payments, partially offset by higher technology revenue. We did not receive shortfall payments in the fourth quarter of 2019 as compared to $1 million in the 2018 quarter. Average operating costs per utilization day for drilling rigs in Canada decreased to $14,791 compared with the prior year quarter of $15,115. The decrease was mainly caused by the impact of lower repair and maintenance costs due to the componentization of rig recertification costs. Excluding the impact of componentization of recertifications, our operating costs on a per day basis for the quarter were $15,044.
  • We realized revenue from international contract drilling of US$43 million in the fourth quarter of 2019, an increase of US$4 million over the prior year period. Average revenue per utilization day in our international contract drilling business was US$52,283 compared with US$51,982 in the respective prior year quarter. The higher average rate in 2019 was primarily due to day rate increases from the renewal and extension of drilling contracts and the deployment of our sixth Kuwait rig.
  • Funds provided by operations (see “NON-GAAP MEASURES”) in the fourth quarter of 2019 were $76 million, a decrease of $17 million from the prior year comparative quarter. Cash provided by operations was $75 million versus $93 million in the prior year quarter. The decrease in funds and cash provided by operations was primarily the result of lower activity and the non-recurring transaction termination fee that was received in the fourth quarter of 2018.
  • Capital expenditures were $22 million in the fourth quarter, $8 million lower than the same period in 2018. Capital spending for the quarter included $8 million for upgrade and expansion capital and $14 million for the maintenance of existing assets, infrastructure spending and intangibles.

Summary for the year ended December 31, 2019:

  • Revenue for the year ended December 31, 2019 totaled $1,541 million, consistent with 2018.
  • Operating earnings (see “NON-GAAP MEASURES”) were $95 million, an increase of $293 million from 2018. As a percentage of revenue, operating earnings improved to 6% compared to negative 13% in 2018. In 2019, operating earnings were positively impacted by increased international drilling activity, higher U.S. and international average day rates, gains on asset disposals, partially offset by lower Canadian drilling activity, the non-recurring transaction termination fee and loss on asset decommissioning and higher share-based compensation expense. In addition, during the fourth quarter of 2018, we incurred goodwill impairment charges of $208 million.
  • General and administrative costs were $104 million, a decrease of $8 million from 2018. The decrease in costs was primarily the result of continued fixed cost control initiatives and the impact of lease-related charges due to the adoption of IFRS 16, partially offset by higher share-based incentive compensation and the weakening of the Canadian dollar on our U.S. dollar denominated costs (see “Other Items” later in this release).
  • Net finance charges were $118 million, a decrease of $9 million from 2018 primarily due to a reduction in interest expense related to debt retired in 2018 and 2019, partially offset by the weakening of the Canadian dollar on our U.S. dollar denominated interest expense.
  • Funds provided by operations (see “NON-GAAP MEASURES”) in 2019 were $293 million, a decrease of $19 million from $311 million in the prior year. Cash provided by operations was $288 million in 2019 as compared to $293 million in 2018. The decrease in funds and cash provided by operations was primarily the result of the non-recurring transaction termination fee that was received in the fourth quarter of 2018.
  • Capital expenditures were $161 million in 2019, an increase of $35 million over 2018. Capital spending for 2019 included $121 million for upgrade and expansion capital and $40 million on the maintenance of existing assets, infrastructure and intangibles. Our 2019 upgrade and expansion capital were mainly comprised of one U.S. new-build, one U.S. SCR to AC Triple upgrade, the Kuwait new-build rig and long-lead capital items. Our new-build and upgraded rigs were backed by long-term drilling contracts.

STRATEGY

Precision’s strategic priorities for 2019 were as follows:

  1. Generate strong free cash flow and utilize $200 million to reduce debt in 2019 – In the fourth quarter of 2019, we generated $75 million in cash provided by operations and further reduced our debt balance by $59 million through open market repurchases and redemptions of our unsecured senior notes. For the full year 2019, Precision exceeded our 2019 debt reduction target with total debt repayments of $205 million.
     
  2. Maximize financial results by leveraging our High Performance, High Value Super Series rig fleet and scale with disciplined cost management – In the fourth quarter of 2019, Precision continued operating at record market share levels in the U.S. and Canada and have leveraged our size and scale to maximize cash flow. In the U.S., operating margins (revenue less operating costs) were up 19% compared to the prior year quarter. Despite decreased Canadian industry activity levels, our Canadian drilling operations generated strong cash flow and our Completion and Production Services business contributed $6 million of Adjusted EBITDA. Precision also continued to leverage its expanded footprint in Kuwait, with our sixth Kuwait rig commencing drilling on July 1, 2019, increasing our economies of scale and operating margins in the region.

    For the full year 2019, Precision reported Adjusted EBITDA of $392 million, up 5% from 2018 despite a 22% reduction in Canadian drilling activity levels.

  3. Full scale commercialization and implementation of our AlphaAutomation platform, AlphaApps and AlphaAnalytics – In the fourth quarter, we announced full commercialization of our AlphaAutomation offering, with its 32 systems over 90% utilized and earning commercial rates. We currently have our AlphaAutomation platform deployed throughout various basins in the U.S. and Canada, drilling 613 wells in 2019, an increase of 69% over the prior year comparative. With more than 15 revenue generating AlphaApps commercialized or in development, our portfolio of technology offerings continues to expand. We have demonstrated to our customers our system’s ability to deliver consistent, high-quality results, and as a result of continued demand to lower well costs and maximize efficiencies, Precision intends to deploy an additional 24 AlphaAutomation systems in North America during 2020.

Precision’s strategic priorities for 2020 are as follows:

  1. Generate strong free cash flow and reduce debt by $100 million to $150 million in 2020 and by $700 million between 2018 and 2022.
  2. Demonstrate operational excellence in all aspects of our business including operational, financial and ESG (environmental, social and governance) metrics.
  3. Leverage our Alpha technology platform as a competitive differentiator and source of financial returns for Precision.

OUTLOOK

For the fourth quarter of 2019, the average price of West Texas Intermediate and Henry Hub were down 3% and 37%, respectively. The average price of Western Canadian Select and AECO gas prices were 111% and 66% higher, respectively.

 Three months ended December 31,  Year ended December 31, 
 2019  2018  2019  2018 
Average oil and natural gas prices               
Oil               
West Texas Intermediate (per barrel) (US$) 57.02   58.89   57.07   64.88 
Western Canadian Select (per barrel) (US$) 41.12   19.47   44.28   38.46 
Natural gas               
United States               
Henry Hub (per MMBtu) (US$) 2.40   3.81   2.56   3.12 
Canada               
AECO (per MMBtu) (Cdn$) 2.47   1.49   1.77   1.49 

Contracts

During 2019 we entered into 56 term contracts. The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2019 and 2020 as of February 12, 2020. For those quarters ended after December 31, 2019, this chart represents the minimum number of term contracts where we will be earning revenue. We expect the actual number of contracted rigs to be higher in future periods as we continue to sign contracts.

  Average for the quarter ended 2019  Average for the quarter ended 2020 
  Mar. 31  June 30  Sept. 30  Dec. 31  Mar. 31  June 30  Sept. 30  Dec. 31 
Average rigs under term contract
  as of February 12, 2020:
                                
U.S.  56   52   49   41   41   34   26   20 
Canada  8   5   5   5   5   4   3   3 
International  8   8   9   9   8   8   6   6 
Total  72   65   63   55   54   46   35   29 

The following chart outlines the average number of drilling rigs under contract for 2019 and the average number of rigs we have under contract for 2020 and 2021 as of February 12, 2020.

  Average for the year ended 
  2019  2020  2021 
Average rigs under term contract
  as of February 12, 2020:
            
U.S.  49   30   5 
Canada  6   4   1 
International  9   7   6 
Total  64   41   12 

In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

The following chart outlines our average number of drilling rigs working or moving by quarter for the periods noted.

 Average for the quarter ended 2018 Average for the quarter ended 2019 
 Mar. 31  June 30  Sept. 30  Dec. 31 Mar. 31  June 30  Sept. 30  Dec. 31 
Average Precision active rig count:                              
U.S. 64   72   76   80  79   77   72   63 
Canada 72   31   52   49  48   27   42   43 
International 8   8   8   8  8   8   9   9 
Total 144   111   136   137  135   112   123   115 

To start 2020, drilling activity has decreased relative to the prior year in the U.S. and Canada. According to industry sources, as of February 12, 2020, the U.S. active land drilling rig count was down 26% compared with the same point last year and the Canadian active land drilling rig count was up approximately 8%. Furthermore, approximately 85% of the U.S. industry’s active rigs and 61% of the Canadian industry’s active rigs were drilling for oil targets, compared with 81% for the U.S. and 60% for Canada at the same time last year.

Industry Conditions

We expect Tier 1 rigs to remain the preferred rigs of customers globally. The economic value created by the significant drilling and mobility efficiencies delivered by the most advanced XY pad walking rigs has been highlighted and widely accepted by our customers. The trend to longer-reach horizontal completions and importance of the rig delivering these complex wells consistently and efficiently has been well established by the industry. We expect demand for leading edge high efficiency Tier 1 rigs will continue to strengthen relative to less capable rigs, as drilling rig capability has been a key economic facilitator of horizontal/unconventional resource exploitation. Development and field application of drilling equipment process automation coupled with closed loop drilling controls and de-manning of rigs will continue this technical evolution while creating further cost efficiencies and performance value for customers.

Capital Spending

Capital spending in 2020 is expected to be $95 million and includes $58 million for sustaining, infrastructure and intangibles and $37 million for upgrade and expansion. We expect our spending to be split $86 million in the Contract Drilling Services segment, $7 million in the Completion and Production Services segment and $2 million to the Corporate segment.

SEGMENTED FINANCIAL RESULTS

Precision’s operations are reported in two segments: Contract Drilling Services, which includes the drilling rig, directional drilling, oilfield supply and manufacturing divisions; and Completion and Production Services, which includes the service rig, rental and camp and catering divisions.

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands of Canadian dollars)2019  2018  % Change  2019  2018  % Change 
Revenue:                       
Contract Drilling Services 338,886   391,843   (13.5)  1,399,068   1,396,492   0.2 
Completion and Production Services 34,985   36,715   (4.7)  147,829   150,760   (1.9)
Inter-segment eliminations (1,570)  (1,548)  1.4   (5,577)  (6,063)  (8.0)
  372,301   427,010   (12.8)  1,541,320   1,541,189   0.0 
Adjusted EBITDA:(1)                       
Contract Drilling Services 112,566   122,131   (7.8)  429,483   412,134   4.2 
Completion and Production Services 6,259   7,011   (10.7)  24,155   14,881   62.3 
Corporate and Other (13,819)  5,350   (358.3)  (61,733)  (51,884)  19.0 
  105,006   134,492   (21.9)  391,905   375,131   4.5 

(1)     See “NON-GAAP MEASURES”.

SEGMENT REVIEW OF CONTRACT DRILLING SERVICES

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands of Canadian dollars, except where noted)2019  2018  % Change  2019  2018  % Change 
Revenue 338,886   391,843   (13.5)  1,399,068   1,396,492   0.2 
Expenses:                       
Operating 216,305   258,255   (16.2)  927,612   945,203   (1.9)
General and administrative 10,015   11,457   (12.6)  38,927   39,155   (0.6)
Restructuring -   -  n/m   3,046   -  n/m 
Adjusted EBITDA(1) 112,566   122,131   (7.8)  429,483   412,134   4.2 
Depreciation 73,196   98,460   (25.7)  300,882   341,712   (11.9)
Gain on asset disposals (3,621)  (2,526)  43.3   (46,849)  (7,157)  554.6 
Loss on asset decommissioning 20,263   -  n/m   20,263   -  n/m 
Reversal of impairment of property, plant and equipment -   -  n/m   (5,810)  -  n/m 
Impairment of goodwill -   207,544   (100.0)  -   207,544   (100.0)
Operating earnings (loss)(1) 22,728   (181,347)  (112.5)  160,997   (129,965)  (223.9)
Operating earnings (loss)(1) as a percentage of revenue 6.7%  (46.3)%      11.5%  (9.3)%    

(1)     See “NON-GAAP MEASURES”.
n/m    Calculation not meaningful.

United States onshore drilling statistics:(1)2019  2018 
 Precision  Industry(2)  Precision  Industry(2) 
Average number of active land rigs for quarters ended:               
March 31 79   1,023   64   951 
June 30 77   967   72   1,021 
September 30 72   896   76   1,032 
December 31 63   798   80   1,050 
Year to date average 73   921   73   1,014 

(1)     United States lower 48 operations only.
(2)     Baker Hughes rig counts.

  Three months ended December 31, 
Canadian onshore drilling statistics:(1) 2019  2018 
  Precision  Industry(2)  Precision  Industry(2) 
Number of drilling rigs (end of period)  109   517   117   574 
Drilling rig operating days (spud to release)  3,496   11,392   4,020   15,235 
Drilling rig operating day utilization  33%  23%  33%  28%
Number of wells drilled  350   1,160   401   1,602 
Average days per well  10.0   9.8   10.0   9.5 
Number of metres drilled (000s)  1,100   3,600   1,153   4,609 
Average metres per well  3,143   3,103   2,874   2,877 
Average metres per day  315   316   287   303 


  Year ended December 31, 
Canadian onshore drilling statistics:(1) 2019  2018 
  Precision  Industry(2)  Precision  Industry(2) 
Number of drilling rigs (end of period)  109   517   117   574 
Drilling rig operating days (spud to release)  12,900   45,334   16,479   64,491 
Drilling rig operating day utilization  31%  22%  34%  29%
Number of wells drilled  1,314   4,769   1,663   6,781 
Average days per well  9.8   9.5   9.9   9.5 
Number of metres drilled (000s)  3,968   14,241   4,694   19,313 
Average metres per well  3,020   2,986   2,823   2,848 
Average metres per day  308   314   285   299 

(1)     Canadian operations only.
(2)    Canadian Association of Oilwell Drilling Contractors (“CAODC”), and Precision – excludes non-CAODC rigs and non-reporting CAODC members.

Revenue from Contract Drilling Services for the fourth quarter of 2019 was $339 million, $53 million lower than the fourth quarter of 2018, while Adjusted EBITDA (see “NON-GAAP MEASURES”) decreased 8% to $113 million. The lower revenue in 2019 was primarily due to lower U.S. and Canada utilization days, partially offset by higher international activity and U.S. pricing. During the quarter, we had US$3 million of revenue from each of idle but contracted rigs and turnkey projects as compared with fourth quarter 2018 idle but contracted rig and turnkey revenue of US$0.3 million and US$11 million, respectively.

Drilling rig utilization days (drilling days plus move days) in both the U.S. and Canada were down in the fourth quarter of 2019 as compared to 2018. In the U.S., we had 5,814 drilling rig utilization days, 21% lower than the same quarter of 2018. Canada had 3,919 days in the quarter, a decrease of 13% compared to 2018. The reduced activity in both regions was consistent with lower industry activity. Drilling rig utilization days in our international business was 818, 11% higher than the same quarter of 2018, as we deployed our sixth Kuwait rig in the third quarter of 2019.

Revenue per utilization day in the U.S. increased in the fourth quarter of 2019 to US$23,949 from US$23,369 in the prior year quarter. The increase was the result of higher day rates, idle but contracted rig revenue and rig technology revenue, partially offset by lower turnkey activity. On a sequential basis, U.S. revenue per utilization day, excluding revenue from turnkey and idle but contracted rigs, was consistent with the third quarter of 2019. In Canada, average revenue per utilization day for contract drilling rigs was $22,182 compared with $22,802 in the fourth quarter of 2018. The lower average revenue per utilization day in the fourth quarter of 2019 was primarily due to lower rates from a higher proportion of Super Singles in our rig mix and lower shortfall payments, partially offset by higher technology revenue. We did not receive shortfall payments in the fourth quarter of 2019 as compared to $1 million in the 2018 quarter. Average revenue per utilization day in our international contract drilling business was US$52,283 compared with US$51,982 in the respective prior year quarter. The higher average rate in 2019 was primarily due to day rate increases from the renewal and extension of drilling contracts and the deployment of the sixth Kuwait rig, partially offset by lower amortization of the initial upfront mobilization revenue. Directional drilling services realized revenue of $9 million in the fourth quarter of 2019, consistent with 2018.

In the U.S., 66% of utilization days were generated from rigs under term contract as compared with 70% in the fourth quarter of 2018. In Canada, 9% of our utilization days in the quarter were generated from rigs under term contract, compared with 15% in the fourth quarter of 2018.

Operating costs were 64% of revenue for the quarter, 2% lower than the prior year quarter. Our U.S. operating costs on a per day basis decreased to US$14,073 in the fourth quarter of 2019 compared with US$15,042 in 2018. The decrease was mainly due to lower turnkey activity, the impact from the reversal of prior period provisions and the componentization of rig recertification costs. Excluding the impact of the provision reversals and componentization of recertification costs, our operating costs on a per day basis for the quarter were US$14,974. In the U.S., on a sequential basis, operating costs per day decreased by US$414 due to lower repair and maintenance costs, third party charges partially offset by higher turnkey costs. Average operating costs per utilization day for drilling rigs in Canada decreased to $14,791 compared with the prior year quarter of $15,115. The decrease was mainly caused by the impact of lower repair and maintenance costs due to the componentization of rig recertification costs. Excluding the impact of componentization of recertifications, our operating costs on a per day basis for the quarter were $15,044.

Depreciation expense in the quarter was 26% lower than the fourth quarter of 2018. The lower 2019 expense was primarily due to asset sales, assets becoming fully depreciated and non-recurring accelerated depreciation of excess spare equipment recorded in the fourth quarter of 2018. In 2019, we recognized a loss on the decommissioning of drilling rigs and ancillary equipment of $20 million. See discussion on rig decommissioning under “Other Items” for additional details.

In the fourth quarter of 2019, through the completion of normal course business operations, we sold used assets resulting in a gain on asset disposals of $4 million as compared to $3 million in the 2018 quarter.

SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands of Canadian dollars, except where noted)2019  2018  % Change  2019  2018  % Change 
Revenue 34,985   36,715   (4.7)  147,829   150,760   (1.9)
Expenses:                       
Operating 26,982   28,515   (5.4)  116,932   128,124   (8.7)
General and administrative 1,744   1,189   46.7   6,285   6,591   (4.6)
Restructuring -   -  n/m   457   1,164   (60.7)
Adjusted EBITDA(1) 6,259   7,011   (10.7)  24,155   14,881   62.3 
Depreciation 4,309   5,416   (20.4)  17,881   22,801   (21.6)
Loss (gain) on asset disposals (201)  (65)  209.2   (3,767)  1,078   (449.4)
Operating earnings (loss)(1) 2,151   1,660   29.6   10,041   (8,998)  (211.6)
Operating earnings (loss)(1) as a percentage of revenue 6.1%  4.5%      6.8%  (6.0)%    
Well servicing statistics:                       
Number of service rigs (end of period)(2) 123   210   (41.4)  123   210   (41.4)
Service rig operating hours 39,865   35,773   11.4   147,154   157,467   (6.5)
Service rig operating hour utilization 35%  19%      32%  21%    
Service rig revenue per operating hour 746   753   (0.9)  739   709   4.2 

(1)     See “NON-GAAP MEASURES”.
(2)     In 2019, 75 rigs were not registered with the industry association and 12 snubbing units were sold.
n/m    Calculation not meaningful.

Revenue from Completion and Production Services decreased $2 million compared with the fourth quarter of 2018 due to lower activity in our rental and camp and catering divisions and the impact of the disposal of our snubbing units and waste water assets partially offset by higher well service activity in Canada and the U.S. Our service rig operating hours in the quarter were up 11% from the fourth quarter of 2018 while average service rig revenue per operating hour decreased slightly to $746. Excluding the impact of snubbing assets, which were disposed in the first quarter, our fourth quarter 2019 service activity and rates increased 20% and 5%, respectively, over the comparative 2018 period. Approximately 78% of our fourth quarter Canadian service rig activity was oil related.

Adjusted EBITDA (see “NON-GAAP MEASURES”) of $6 million in the fourth quarter of 2019 was 11% lower than the 2018 quarter primarily due to lower activity in our non-well servicing divisions and the impact of asset disposals, partially offset by higher well service activity and lower costs resulting from our cost control measures.

During the fourth quarter, the segment generated 81% of its revenue from Canadian operations and 19% from U.S. operations compared with 90% from Canada and 10% in the U.S. in the 2018 quarter.

Operating costs as a percentage of revenue was 77% compared with the prior year comparative quarter of 78%. The reduction of operating costs as a percentage of revenue was primarily the result of a higher proportion of 24-hour well service work and continued cost control.

Depreciation expense in the quarter was 20% lower than the prior year comparative period. The decrease in depreciation expense was primarily due to a lower capital asset base resulting from the disposition of snubbing units and waste water assets and assets becoming fully depreciated.

In the first quarter of 2019, as a cost control measure, Precision did not renew the registration of 75 Canadian-based well service rigs with industry associations due to low anticipated activity levels for the year.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had negative Adjusted EBITDA (see “NON-GAAP MEASURES”) of $14 million compared with Adjusted EBITDA of $5 million in the comparative 2018 quarter. The lower Adjusted EBITDA in 2019 was primarily the result of higher share-based incentive compensation in the current quarter and the non-recurring receipt of the transaction termination fee in the fourth quarter of 2018.

OTHER ITEMS

Share-based Incentive Compensation Plans

We have several cash-settled share-based incentive plans and two equity-settled share-based incentive plans. Details of vesting conditions, fair value determination and accounting policy for each plan can be found in the notes to our consolidated annual financial statements for the year ended December 31, 2018.

A summary of the amounts expensed under these plans during the reporting periods are as follows:

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands of Canadian dollars)2019  2018  2019  2018 
Cash settled share-based incentive plans 3,529   (14,208)  8,193   6,391 
Equity settled share-based incentive plans:               
Executive PSU 3,149   1,527   11,648   5,871 
Stock option plan 524   681   2,275   3,336 
Total share-based incentive compensation plan expense 7,202   (12,000)  22,116   15,598 
                
Allocated:               
Operating 1,711   (5,437)  5,025   3,656 
General and Administrative 5,491   (6,563)  17,091   11,942 
  7,202   (12,000)  22,116   15,598 

Cash settled shared-based compensation expense for the fourth quarter of 2019 was an expense of $4 million compared to a recovery of $14 million in the comparable 2018 quarter. The higher share-based compensation expense in 2019 was the result of our share price increasing in the 2019 fourth quarter versus a decline in the 2018 quarter.

Executive PSU share-based incentive compensation expense for the quarter was $3 million compared with $2 million in the same quarter in 2018. The increased compensation expense was the result of additional Executive PSUs granted in 2019 offset partially by lower fair values for the 2019 grants.

Finance Charges

Net finance charges were $28 million, a decrease of $4 million compared with the fourth quarter of 2018, primarily due to a reduction in interest expense related to the debt retired in 2018 and 2019, partially offset by the impact of the adoption of IFRS 16. Interest charges on our U.S. denominated long-term debt in the fourth quarter of 2019 were US$20 million ($26 million) compared with US$23 million ($30 million) in 2018.

Normal Course Issuer Bid

In 2019, the Toronto Stock Exchange approved our application to implement a Normal Course Issuer Bid. As at December 31, 2019, we purchased and cancelled a total of 16 million common shares for $26 million. Subsequent to December 31, 2019, we purchased and cancelled an additional 2 million common shares for $3 million.

Rig Decommissioning

In the fourth quarter of 2019, we decommissioned certain drilling and ancillary equipment that no longer met our High-Performance technology standards. Included in the decommissioned assets were those drilling rigs previously held for sale. We recognized a $20 million loss on the decommissioning of these assets.

Change in Rig Components

In the fourth quarter of 2019, we performed our annual review of estimated useful lives, residual values and methods and components of depreciation of property, plant and equipment. Due to changes in circumstance surrounding the timing, nature and complexity of rig recertifications, we determined the associated costs represent a separate component of property, plant and equipment. This change has been recognized prospectively and is expected to increase our 2020 depreciation expense by approximately $3 million.

Income Tax

Income tax recovery for the quarter was $12 million compared with $2 million in the same quarter in 2018. In 2019, the Province of Alberta announced various reductions to corporate income tax rates, that when fully implemented over the next three years will decrease the provincial corporate income tax rate from 12% to 8% by 2022. The increase in the income tax recovery for the quarter was mainly due to a larger fourth quarter loss prior to the non-taxable portion of the goodwill impairment in 2018; adjustments for prior period taxes; reversal of unrecognized tax benefits; and U.S. tax reform legislation clarification enacted in December 2019, offset by a reduction in the benefit from the Alberta income tax rate reductions.

LIQUIDITY AND CAPITAL RESOURCES

The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our growth and cash flow, regardless of where we are in the business cycle. We maintain a variable operating cost structure so we can be responsive to changes in demand.

Our maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through our internal manufacturing and supply capabilities. Term contracts on expansion capital for new-build and upgrade rig programs provide more certainty of future revenues and return on our capital investments.

Liquidity

Amount Availability Used for Maturity
Senior credit facility (secured)      
US$500 million (extendible, revolving term credit facility with US$300 million accordion feature) Undrawn, except US$25 million in outstanding letters of credit General corporate purposes November 21, 2023
Operating facilities (secured)      
$40 million Undrawn, except $26 million in outstanding letters of credit Letters of credit and general corporate purposes  
US$15 million Undrawn Short term working capital requirements  
Demand letter of credit facility (secured)      
US$30 million Undrawn, except US$2 million in outstanding letters of credit Letters of credit  
Unsecured senior notes  (unsecured)      
US$91 million – 6.5% Fully drawn Capital expenditures and general corporate purposes December 15, 2021
US$345 million – 7.75% Fully drawn Debt redemption and repurchases December 15, 2023
US$308 million – 5.25% Fully drawn Capital expenditures and general corporate purposes November 15, 2024
US$370 million – 7.125% Fully drawn Debt redemption and repurchases  January 15, 2026

As of December 31, 2019, we had US$1,113 million ($1,445 million) outstanding under our unsecured senior notes as compared with US$1,267 million ($1,729 million) at December 31, 2018. The current blended cash interest cost of our debt is approximately 6.8%.

During 2019, we repurchased and cancelled US$30 million of our 7.125% unsecured senior notes due 2026, US$5 million of our 7.75% notes due 2023 and US$43 million of our 5.25% notes due 2024. In addition, we redeemed US$75 million principal amount of our 6.50% unsecured senior notes due 2021.

Subsequent to December 31, 2019, we redeemed an additional US$25 million of our 6.5% unsecured senior notes due 2021.

Covenants

Following is a listing of our currently applicable covenants and the calculations as of December 31, 2019:

 Covenant At December 31, 2019 
Senior Credit Facility     
Consolidated senior debt to consolidated covenant EBITDA(1)≤ 2.50  0.00 
Consolidated covenant EBITDA to consolidated interest expense(1)≥ 2.50  3.39 
Unsecured Senior Notes     
Consolidated interest coverage ratio≥ 2.00  3.30 

(1)     For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.

At December 31, 2019, we were in compliance with the covenants of our senior credit facility and unsecured senior notes.

Senior Credit Facility

The senior credit facility requires that we comply with certain restrictive and financial covenants including a leverage ratio of consolidated senior debt to consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.

Under the senior credit facility, we are required to maintain a ratio of consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) to consolidated interest expense, for the most recent four consecutive quarters, of greater than 2.5:1.

Unsecured Senior Notes

Our unsecured senior notes require we comply with restrictive and financial covenants including an incurrence based consolidated interest coverage ratio test of consolidated cash flow, as defined in the unsecured senior note agreements, to consolidated interest expense of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event this ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters, the unsecured senior notes restrict our ability to incur additional indebtedness.

The unsecured senior notes contain a restricted payment covenant that limits our ability to make payments in the nature of dividends, distributions and for repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2021 and 2024 unsecured senior notes, from October 1, 2016 for the 2023 unsecured senior notes and October 1, 2017 for the 2026 unsecured senior notes by, among other things, 50% of consolidated cumulative net earnings and decreases by 100% of consolidated cumulative net losses, as defined in the note agreements, and payments made to shareholders. Beginning with the December 31, 2015 calculation the governing net restricted payments basket was negative which limits our ability to declare and make dividend payments or share repurchases until such time as the governing restricted payments basket becomes positive.

For further information, please see the unsecured senior note indentures which are available on SEDAR and EDGAR.

Impact of foreign exchange rates

On average, the Canada-U.S. foreign exchange rate was consistent in the fourth quarter of 2019 as compared to 2018. For the year ended December 31, 2019, the Canadian dollar weakened by 2% from 2018. The devaluation of the Canadian dollar resulted in higher translated U.S. denominated revenue and costs. The following table summarizes the average and closing Canada-U.S. foreign exchanges rates:

 Three months ended December 31,  Year ended December 31, 
 2019  2018  2019  2018 
Canada-U.S. foreign exchange rates               
Average 1.32   1.32   1.33   1.30 
Closing 1.30   1.37   1.30   1.37 

Hedge of investments in foreign operations

We utilize foreign currency long-term debt to hedge our exposure to changes in the carrying values of our net investment in certain foreign operations as a result of changes in foreign exchange rates.

We have designated our U.S. dollar denominated long-term debt as a net investment hedge in our U.S. operations and other foreign operations that have a U.S. dollar functional currency. To be accounted for as a hedge, the foreign currency denominated long-term debt must be designated and documented as such and must be effective at inception and on an ongoing basis. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective amounts (if any) in net earnings (loss).

Average shares outstanding

The following table reconciles the weighted average shares outstanding used in computing basic and diluted net earnings (loss) per share:

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands)2019  2018  2019  2018 
Weighted average shares outstanding – basic 282,850   293,782   290,782   293,560 
Effect of stock options and other equity compensation plans       6,397    
Weighted average shares outstanding – diluted 282,850   293,782   297,179   293,560 

QUARTERLY FINANCIAL SUMMARY

 (Stated in thousands of Canadian dollars, except per share amounts) 2019 
Quarters ended March 31  June 30  September 30  December 31 
Revenue  434,043   359,424   375,552   372,301 
Adjusted EBITDA(1)  107,967   81,037   97,895   105,006 
Net earnings (loss)  25,014   (13,801)  (3,534)  (1,061)
Net earnings (loss) per basic share  0.09   (0.05)  (0.01)  (0.00)
Net earnings (loss) per diluted share  0.08   (0.05)  (0.01)  (0.00)
Funds provided by operations(1)  95,993   40,950   79,930   75,779 
Cash provided by operations  40,587   106,035   66,556   74,981 


 (Stated in thousands of Canadian dollars, except per share amounts) 2018 
Quarters ended March 31  June 30  September 30  December 31 
Revenue  401,006   330,716   382,457   427,010 
Adjusted EBITDA(1)  97,469   62,182   80,988   134,492 
Net loss  (18,077)  (47,217)  (30,648)  (198,328)
Net loss per basic  (0.06)  (0.16)  (0.10)  (0.68)
Net loss per diluted share  (0.06)  (0.16)  (0.10)  (0.68)
Funds provided by operations(1)  104,026   50,225   64,368   92,595 
Cash provided by operations  38,189   129,695   31,961   93,489 

(1)     See “NON-GAAP MEASURES”.

CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgments and estimates in preparing our Condensed Interim Consolidated Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments and estimates used in preparing the Condensed Interim Consolidated Financial Statements are described in our 2018 Annual Report and there have been no material changes to our critical accounting judgments and estimates during the three months and year ended December 31, 2019 except for those impacted by the adoption of new accounting standards.

CHANGES IN ACCOUNTING POLICY

New standards adopted

The following standards became effective on January 1, 2019:

  • IFRS 16 Leases

  • IFRIC 23 Uncertainty over Income Tax Treatments

Precision adopted these standards using the modified retrospective method on January 1, 2019. Please see the unaudited September 30, 2019 Condensed Interim Consolidated Financial Statements and related notes for further details on the adoption of these standards.

Impact of IFRS 16 Leases on Adjusted EBITDA

With the adoption of IFRS 16, the accounting treatment for operating leases when Precision is the lessee, changed effective January 1, 2019. Precision adopted IFRS 16 using the modified retrospective approach and our comparative information was not restated. As a result, the comparability of our 2019 Adjusted EBITDA to periods prior to January 1, 2019 is impacted.

Under IFRS 16, leases classified as operating leases were recognized on our statement of financial position with a right of use asset and corresponding lease obligation representing the present value of Precision’s future lease payments. Once recognized, right of use assets are depreciated over the shorter of their useful life and the term of the lease. The lease obligation is measured at amortized cost using the effective interest method. Under this approach, an interest charge is applied to accrete the lease obligation to the present value of future lease payments. As lease payments are made, the lease obligation is reduced.

Historically, operating lease obligations were accounted for as ‘off-balance sheet’ and lease expenses were only recognized at the time of payment in either operating or general and administrative expense. However, under IFRS 16, lease costs are reflected on the statement of earnings (loss) through depreciation and interest expense, resulting in an increase to Adjusted EBITDA.

Upon transition, we recognized right of use assets and corresponding lease obligations of $73 million. For the three months and year ended December 31, 2019, we recorded lease interest charges of $1 million and $3 million and depreciated our right of use assets by $2 million and $8 million, respectively. As a result of the new lease standard, our Adjusted EBITDA was positively impacted for the three months and year ended December 31, 2019 by $3 million and $11 million, respectively.

NON-GAAP MEASURES

In this release we reference non-GAAP (Generally Accepted Accounting Principles) measures. Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital are terms used by us to assess performance as we believe they provide useful supplemental information to investors. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies.

Adjusted EBITDA

We believe that Adjusted EBITDA (earnings before income taxes, gain on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, reversal of impairment of property, plant and equipment, loss on asset decommissioning, gain on asset disposals and depreciation and amortization), as reported in the Interim Consolidated Statement of Earnings (Loss), is a useful measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and depreciation and amortization charges.

Covenant EBITDA

Covenant EBITDA, as defined in our senior credit facility agreement, is used in determining the Corporation’s compliance with its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs, certain foreign exchange amounts and with the adoption of the new lease standard IFRS 16 - Leases, the deduction of cash lease payments incurred after December 31, 2018.

Operating Earnings (Loss)

We believe that operating earnings (loss) is a useful measure because it provides an indication of the results of our principal business activities before consideration of how those activities are financed and the impact of foreign exchange and taxation. Operating earnings (loss) is calculated as follows:

 Three months ended December 31,  Year ended December 31, 
(Stated in thousands of Canadian dollars)2019  2018  2019  2018 
Revenue 372,301   427,010   1,541,320   1,541,189 
Expenses:               
Operating 241,717   285,222   1,038,967   1,067,264 
General and administrative 25,578   21,496   104,010   111,830 
Restructuring       6,438   1,164 
Other    (14,200)     (14,200)
Depreciation and amortization 80,932   106,946   333,616   377,044 
Gain on asset disposals (3,888)  (7,905)  (50,741)  (11,384)
Loss on asset decommissioning 20,263      20,263    
Reversal of impairment of property, plant and equipment       (5,810)   
Impairment of goodwill    207,544      207,544 
Operating earnings (loss) 7,699   (172,093)  94,577   (198,073)
Foreign exchange (4,306)  3,198   (8,722)  4,017 
Finance charges 28,275   32,220   118,453   127,178 
Gain on repurchase and redemption of unsecured notes (3,178)  (6,848)  (6,815)  (5,672)
Loss before income taxes (13,092)  (200,663)  (8,339)  (323,596)

Funds Provided By (Used In) Operations

We believe that funds provided by (used in) operations, as reported in the Interim Consolidated Statements of Cash Flow, is a useful measure because it provides an indication of the funds our principal business activities generate prior to consideration of working capital, which is primarily made up of highly liquid balances.

Working Capital

We define working capital as current assets less current liabilities as reported on the Condensed Interim Consolidated Statement of Financial Position.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this release, including statements that contain words such as "could", "should", "can", "anticipate", "estimate", "intend", "plan", "expect", "believe", "will", "may", "continue", "project", "potential" and similar expressions and statements relating to matters that are not historical facts constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and "forward-looking statements" within the meaning of the "safe harbor" provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively, "forward-looking information and statements").

In particular, forward looking information and statements include, but are not limited to, the following:

  • our strategic priorities for 2020;
  • our capital expenditure plans for 2020;
  • anticipated activity levels in 2020;
  • anticipated demand for Tier 1 rigs;
  • the average number of term contracts in place for 2020 and 2021;
  • our future debt reduction plans; and
  • our commercialization and expansion of technology offerings.

These forward-looking information and statements are based on certain assumptions and analysis made by Precision in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. These include, among other things:

  • the fluctuation in oil prices may pressure customers into reducing or limiting their drilling budgets;
  • the status of current negotiations with our customers and vendors;
  • customer focus on safety performance;
  • existing term contracts are neither renewed nor terminated prematurely;
  • our ability to deliver rigs to customers on a timely basis; and
  • the general stability of the economic and political environments in the jurisdictions where we operate.

Undue reliance should not be placed on forward-looking information and statements. Whether actual results, performance or achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from our expectations. Such risks and uncertainties include, but are not limited to:

  • volatility in the price and demand for oil and natural gas;
  • fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services;
  • our customers’ inability to obtain adequate credit or financing to support their drilling and production activity;
  • changes in drilling and well servicing technology which could reduce demand for certain rigs or put us at a competitive disadvantage;
  • shortages, delays and interruptions in the delivery of equipment supplies and other key inputs;
  • the effects of seasonal and weather conditions on operations and facilities;
  • the availability of qualified personnel and management;
  • a decline in our safety performance which could result in lower demand for our services;
  • changes in environmental laws and regulations such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an adverse impact on the demand for oil and gas;
  • terrorism, social, civil and political unrest in the foreign jurisdictions where we operate;
  • fluctuations in foreign exchange, interest rates and tax rates; and
  • other unforeseen conditions which could impact the use of services supplied by Precision and Precision’s ability to respond to such conditions.

Readers are cautioned that the forgoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision’s Annual Information Form for the year ended December 31, 2018, which may be accessed on Precision’s SEDAR profile at www.sedar.com or under Precision’s EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, except as required by law.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

 (Stated in thousands of Canadian dollars) December 31, 2019  December 31, 2018 
ASSETS        
Current assets:        
Cash $74,701  $96,626 
Accounts receivable  310,204   372,336 
Income tax recoverable  1,142    
Inventory  31,718   34,081 
Assets held for sale     19,658 
Total current assets  417,765   522,701 
Non-current assets:        
Income tax recoverable     2,449 
Deferred tax assets  4,724   36,880 
Right of use assets  66,142    
Property, plant and equipment  2,749,463   3,038,612 
Intangibles  31,746   35,401 
Total non-current assets  2,852,075   3,113,342 
Total assets $3,269,840  $3,636,043 
         
LIABILITIES AND EQUITY        
Current liabilities:        
Accounts payable and accrued liabilities $199,478  $274,489 
Income taxes payable  4,142   7,673 
Lease obligation  12,449    
Total current liabilities  216,069   282,162 
Non-current liabilities:        
Share-based compensation  8,830   6,520 
Provisions and other  9,959   10,577 
Lease obligation  54,980    
Long-term debt  1,427,181   1,706,253 
Deferred tax liabilities  25,389   72,779 
Total non-current liabilities  1,526,339   1,796,129 
Shareholders’ equity:        
Shareholders’ capital  2,296,378   2,322,280 
Contributed surplus  66,255   52,332 
Deficit  (969,456)  (978,874)
Accumulated other comprehensive income  134,255   162,014 
Total shareholders’ equity  1,527,432   1,557,752 
Total liabilities and shareholders’ equity $3,269,840  $3,636,043 
         


CONDENSED INTERIM CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) (UNAUDITED)

  Three Months Ended December 31,  Year Ended December 31, 
(Stated in thousands of Canadian dollars, except per share amounts) 2019  2018  2019  2018 
                 
                 
Revenue $372,301  $427,010  $1,541,320  $1,541,189 
Expenses:                
Operating  241,717   285,222   1,038,967   1,067,264 
General and administrative  25,578   21,496   104,010   111,830 
Restructuring        6,438   1,164 
Other recoveries     (14,200)     (14,200)
Earnings before income taxes, gain on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, reversal of impairment of property, plant and equipment, loss on asset decommissioning, gain on asset disposals and depreciation and amortization  105,006   134,492   391,905   375,131 
Depreciation and amortization  80,932   106,946   333,616   377,044 
Gain on asset disposals  (3,888)  (7,905)  (50,741)  (11,384)
Loss on asset decommissioning  20,263      20,263    
Reversal of impairment of property, plant and equipment        (5,810)   
Impairment of goodwill     207,544      207,544 
Foreign exchange  (4,306)  3,198   (8,722)  4,017 
Finance charges  28,275   32,220   118,453   127,178 
Gain on repurchase and redemption of unsecured senior notes  (3,178)  (6,848)  (6,815)  (5,672)
Loss before income taxes  (13,092)  (200,663)  (8,339)  (323,596)
Income taxes:                
Current  (3,473)  2,177   1,080   8,573 
Deferred  (8,558)  (4,512)  (16,037)  (37,899)
   (12,031)  (2,335)  (14,957)  (29,326)
Net earnings (loss) $(1,061) $(198,328) $6,618  $(294,270)
Net earnings (loss) per share:                
Basic $(0.00) $(0.68) $0.02  $(1.00)
Diluted $(0.00) $(0.68) $0.02  $(1.00)
                 


CONDENSED INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

  Three Months Ended December 31,  Year Ended December 31, 
(Stated in thousands of Canadian dollars) 2019  2018  2019  2018 
Net earnings (loss) $(1,061) $(198,328) $6,618  $(294,270)
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency  (41,849)  128,674   (106,781)  175,630 
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax  28,941   (104,716)  79,022   (145,226)
Comprehensive loss $(13,969) $(174,370) $(21,141) $(263,866)
                 


CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

  Three Months Ended December 31,  Year Ended December 31, 
(Stated in thousands of Canadian dollars) 2019  2018  2019  2018 
Cash provided by (used in):                
Operations:                
  Net earnings (loss) $(1,061) $(198,328) $6,618  $(294,270)
  Adjustments for:                
  Long-term compensation plans  6,072   (1,599)  19,457   17,401 
  Depreciation and amortization  80,932   106,946   333,616   377,044 
  Gain on asset disposals  (3,888)  (7,905)  (50,741)  (11,384)
  Loss on asset decommissioning  20,263      20,263    
  Reversal of impairment of property, plant and equipment        (5,810)   
  Impairment of goodwill     207,544      207,544 
  Foreign exchange  (4,263)  2,556   (8,585)  2,341 
  Finance charges  28,275   32,220   118,453   127,178 
  Income taxes  (12,031)  (2,335)  (14,957)  (29,326)
  Other  (783)  (27)  (981)  (1,269)
  Gain on repurchase and redemption of unsecured senior notes  (3,178)  (6,848)  (6,815)  (5,672)
  Income taxes paid  (316)  (477)  (5,060)  (4,446)
  Income taxes recovered  1,337   1,775   2,479   33,283 
  Interest paid  (35,919)  (41,369)  (116,655)  (108,622)
  Interest received  339   442   1,370   1,412 
Funds provided by operations  75,779   92,595   292,652   311,214 
Changes in non-cash working capital balances  (798)  894   (4,493)  (17,880)
   74,981   93,489   288,159   293,334 
Investments:                
Purchase of property, plant and equipment  (21,541)  (29,594)  (159,886)  (114,576)
Purchase of intangibles  (332)  (687)  (808)  (11,567)
Proceeds on sale of property, plant and equipment  4,931   12,020   90,768   24,457 
  Changes in non-cash working capital balances  609   (1,190)  (4,574)  892 
   (16,333)  (19,451)  (74,500)  (100,794)
Financing:                
Redemption and repurchase of unsecured senior notes  (55,812)  (92,065)  (198,387)  (168,722)
Share repurchase  (17,719)     (25,902)   
Lease payments  (1,699)     (6,823)   
Debt amendment fees  (702)  (638)  (702)  (638)
Issuance of common shares on the exercise of options           275 
   (75,932)  (92,703)  (231,814)  (169,085)
Effect of exchange rate changes on cash  (1,776)  5,529   (3,770)  8,090 
Increase (decrease) in cash  (19,060)  (13,136)  (21,925)  31,545 
Cash, beginning of period  93,761   109,762   96,626   65,081 
Cash, end of period $74,701  $96,626  $74,701  $96,626 
                 


CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)

(Stated in thousands of Canadian dollars) Shareholders’
capital
  Contributed
surplus
  Accumulated
other
comprehensive
income
  Deficit  Total
equity
 
Balance at January 1, 2019 $2,322,280  $52,332  $162,014  $(978,874) $1,557,752 
Lease transition adjustment           2,800   2,800 
Net earnings for the period           6,618   6,618 
Other comprehensive loss for the period        (27,759)     (27,759)
Share repurchase  (25,902)           (25,902)
Share-based compensation expense     13,923         13,923 
Balance at December 31, 2019 $2,296,378  $66,255  $134,255  $(969,456) $1,527,432 


(Stated in thousands of Canadian dollars) Shareholders’
capital
  Contributed
surplus
  Accumulated
other
comprehensive
income
  Deficit  Total
equity
 
Balance at January 1, 2018 $2,319,293  $44,037  $131,610  $(684,604) $1,810,336 
Net loss for the period           (294,270)  (294,270)
Other comprehensive income for the period        30,404      30,404 
Shares issued on redemption non-management directors' DSUs  2,609   (809)        1,800 
Share options exercised  378   (103)        275 
Share-based compensation expense     9,207         9,207 
Balance at December 31, 2018 $2,322,280  $52,332  $162,014  $(978,874) $1,557,752 
                     


FOURTH QUARTER 2019 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation (“Precision”) intends to release its 2019 fourth quarter results before the market opens on Thursday, February 13, 2020, and has scheduled a conference call and webcast to begin promptly at 12:00 Noon MT (2:00 p.m. ET) on the same day.

The conference call dial in numbers are 844-515-9176 or 614-999-9312.

A live webcast of the conference call will be accessible on Precision’s website at www.precisiondrilling.com by selecting “Investor Relations”, then “Webcasts & Presentations”. Shortly after the live webcast, an archived version will be available for approximately 60 days.

An archived recording of the conference call will be available approximately one hour after the completion of the call until February 19, 2020 by dialing 855-859-2056 or 404-537-3406, passcode 9196243.

About Precision

Precision is a leading provider of safe and High Performance, High Value services to the oil and gas industry. Precision provides customers with access to an extensive fleet of Super Series drilling rigs supported by an industry leading technology platform that offers innovative drilling solutions to deliver efficient, predictable and repeatable results through service differentiation. Precision also offers directional drilling services, well service rigs, camps and rental equipment all backed by a comprehensive mix of technical support services and skilled, experienced personnel.

Precision is headquartered in Calgary, Alberta, Canada.  Precision is listed on the Toronto Stock Exchange under the trading symbol “PD” and on the New York Stock Exchange under the trading symbol “PDS”.

For further information, please contact:

Carey Ford, Senior Vice President and Chief Financial Officer
713.435.6100

Dustin Honing, Manager, Investor Relations
403.716.4500

800, 525 - 8th Avenue S.W.
Calgary, Alberta, Canada T2P 1G1
Website:  www.precisiondrilling.com

Primary Logo


Source: GlobeNewswire (February 13, 2020 - 6:00 AM EST)

News by QuoteMedia
www.quotemedia.com

Recent Company Earnings:


January 30, 2024

Oil and Gas 360


 Record Q4 2023 Sales Volumes Near High End of Guidance ~

~ Further Reduced Debt in Addition to Making Final Payment for the Founders Acquisition ~

THE WOODLANDS, Texas, Jan. 29, 2024 (GLOBE NEWSWIRE) — Ring Energy, Inc. (NYSE American: REI) (“Ring” or the “Company”) today provided an operational and financial update for the fourth quarter of 2023, as well as production and capital spending guidance for the first quarter of 2024.

Key Highlights

  • Fourth quarter 2023 sales volumes were approximately 19,400 barrels of oil equivalent per day (“Boe/d”) (70% oil), near the high end of the Company’s guidance, which was 18,900 to 19,500 Boe/d;
  • Positively impacting fourth quarter sales was three full months of production from the recently completed acquisition of the Founders Oil & Gas IV, LLC (“Founders” and the “Founders Acquisition”) assets that closed on August 15, 2023, as well as the success of the Company’s 2023 development program that concluded in late November;
  • Further reduced debt by $3.0 million in the fourth quarter of 2023, while also funding the $11.9 million final payment in December for the Founders Acquisition;
    • Ended 2023 with $425 million of borrowings against the Company’s credit facility;
  • Guiding first quarter 2024 average sales to be 18,000 to 18,500 Boe/d (~69% oil);
    • Impacting the Company’s sales to date was deferred production of approximately 1,900 Boe/d for 10 days, which was associated with recent severe cold winter weather. Production has since been restored;
    • Ring completed its 2023 drilling program in late November and initiated its 2024 program in early January, with the first well expected to be online in February; and
  • Anticipate first quarter capital spending of $37 million to $42 million, primarily associated with a phased, two-rig drilling program (one horizontal and one vertical);
    • Plan to drill four to five horizontal wells and four to six vertical wells.

Mr. Paul D. McKinney, Chairman of the Board and Chief Executive Officer, commented, “We enjoyed record sales during the fourth quarter of 2023 near the high end of guidance, but more importantly exceeded the high end of our expectations for crude oil sales. The result was an outstanding fourth quarter and we look forward to reporting our full results in early March. Contributing to our success in the period was a full quarter of production impact from our recent Founders Acquisition, as well as the ongoing success of our 2023 drilling program that concluded in late November. In addition, we paid down debt by $3.0 million while making our final deferred payment of $11.9 million for the Founders Acquisition. Debt reduction remains a key priority for the Company, and our targeted acquisitions in 2022 and 2023 are allowing us to pay down debt at a much faster rate than we would have done on a standalone basis.”

Mr. McKinney concluded, “As we enter 2024, we intend to retain the flexibility to adjust capital spending levels commensurate with changing oil and gas prices. We began 2024 with a phased, two-rig drilling program, targeting our highest rate-of-return horizontal and vertical drilling inventory. This approach provides us with the flexibility necessary to respond to changing market conditions. As in the past, our efforts are squarely focused on enhancing the financial position of the Company, with further debt reduction a top priority. We appreciate the support of our stockholders and look forward to a successful 2024.”

About Ring Energy, Inc.

Ring Energy, Inc. is an oil and gas exploration, development, and production company with current operations focused on the development of its Permian Basin assets. For additional information, please visit www.ringenergy.com.

Safe Harbor Statement

This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements involve a wide variety of risks and uncertainties, and include, without limitation, statements with respect to the Company’s strategy and prospects. The forward-looking statements include statements about expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of the Company, and plans and objectives of management for future operations. Forward-looking statements are based on current expectations and assumptions and analyses made by Ring and its management in light of their experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actual results and developments will conform to expectations is subject to a number of material risks and uncertainties, including but not limited to: declines in oil, natural gas liquids or natural gas prices; the level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base and interest rates under the Company’s credit facility; Ring’s ability to generate sufficient cash flows from operations to meet the internally funded portion of its capital expenditures budget; the impacts of hedging on results of operations; and Ring’s ability to replace oil and natural gas reserves. Such statements are subject to certain risks and uncertainties which are disclosed in the Company’s reports filed with the Securities and Exchange Commission, including its Form 10-K for the fiscal year ended December 31, 2022, and its other filings. Ring undertakes no obligation to revise or update publicly any forward-looking statements except as required by law.

Contact Information

Al Petrie Advisors
Al Petrie, Senior Partner
Phone: 281-975-2146
Email: apetrie@ringenergy.com


Primary Logo

Source: Ring Energy, Inc.

December 1, 2023

Oil and Gas 360


11/30/2023 – Completed transformational acquisition of Chesapeake’s remaining South Texas assets

Preliminary 2024 outlook of 551-611 MMcfe/d; liquids to comprise ~40% of production mix

Anticipated 2024 capex of $550-$580 million supports 3-rig drilling program

The Company now holds over 220,000 net acres with 1,000 drilling locations identified

Capital structure provides for ~$500 million of liquidity by year-end 2023 and extended maturity

SilverBow Resources announces closing of Chesapeake acquisition and provides updated 2023 guidance & preliminary 2024 outlook- oil and gas 360

SilverBow Resources, Inc. (NYSE: SBOW) (“SilverBow” or “the Company”) announced today the closing of its acquisition of Chesapeake Energy Corporation’s (“Chesapeake”) oil and gas assets in South Texas for a purchase price of $700 million, comprised of a $650 million upfront cash payment paid at closing and an additional $50 million deferred cash payment due 12 months post close, subject to customary adjustments (the “Chesapeake Transaction”). Consideration for the purchase was funded with cash on hand, borrowings under the Credit Facility (as defined below) and proceeds from the sale of additional second lien notes. Chesapeake may also receive up to $50 million in additional contingent cash consideration based on future commodity prices. In addition, the Company provided updated 2023 guidance and a preliminary 2024 outlook.

MANAGEMENT COMMENTS

Sean Woolverton, SilverBow’s Chief Executive Officer, commented, “We are excited to close the Chesapeake Transaction, which materially increases our scale in South Texas and transforms SilverBow into the largest public pure-play Eagle Ford operator. Our differentiated growth and acquisition strategy has positioned us with a stronger balance sheet, a broader commodity mix and a portfolio of locations across a single, geographically advantaged basin. The acquired Chesapeake assets further enhance our optionality to continue allocating capital to our highest return projects and will immediately compete for capital.”

Mr. Woolverton commented further, “The SilverBow team looks forward to extending its proven track record of integrating and growing assets in South Texas through a combination of its existing team and the new employees recently hired from Chesapeake. We plan to expand our capital program to develop the high return inventory acquired, with three rigs running across our portfolio in 2024. Our current expectation is to run two rigs on our liquids properties and one rig on our dry gas properties. As always, our development plan and capital allocation remain flexible based on prevailing commodity prices. Strong production growth is expected to generate significant free cash flow which will allow us to pay down debt, reduce leverage to 1.0x and below and stay opportunistic towards our strategic objectives.”

2023 GUIDANCE & PRELIMINARY 2024 OUTLOOK

SilverBow’s updated 2023 guidance and preliminary 2024 outlook are provided in the table below, inclusive of the acquired Chesapeake assets.

Updated 2023 Guidance & Preliminary 2024 Outlook

4Q23

FY23

FY24

Production Volumes:

Oil (BBLS/D)

18,000 – 20,000

14,300 – 14,900

23,500 – 26,500

Gas (MMCF/D)

230 – 255

214 – 221

320 – 350

NGL (BBLS/D)

10,000 – 12,000

7,850 – 8,350

15,000 – 17,000

Total Reported Production (MMCFE/D)

398 – 447

347 – 361

551 – 611

% Gas

57%

61%

58%

Costs & Expenses:

Lease Operating Expenses ($/MCFE)

$0.63 – $0.67

$0.68 – $0.72

$0.57 – $0.63

Transportation and Processing ($/MCFE)

$0.53 – $0.57

$0.44 – $0.48

$0.76 – $0.84

Production Taxes (% of Sales)

6.0% – 7.0%

6.0% – 7.0%

6.0% – 7.0%

Cash G&A ($MM)

$3.7 – $4.2

$17.1 – $17.6

$22.0 – $23.0

Capital Expenditures ($MM)

$75 – $95

$400 – $425

$550 – $580

For the remainder of 2023, there is no material change to SilverBow’s development plans as previously provided in early November. SilverBow expects to continue operating two drilling rigs across its acreage and does not anticipate any incremental capex on the acquired assets. The Company’s full year 2023 free cash flow range of $40-$60 million represents a 67% increase at the midpoint from SilverBow’s prior range and includes one month of contribution from the acquired assets. For 2024, SilverBow plans to operate three drilling rigs with one rig dedicated to the recently acquired assets. Oil production is expected to increase ~70% year-over-year and average 25,000 barrels per day (“Bbls/d”). The Company’s full year production mix is expected to be more than 40% oil/NGLs.

RISK MANAGEMENT

To help manage the impacts of commodity price movements, SilverBow utilizes various financial derivative contracts to reduce the volatility of its revenues. For 2024, the Company has entered into hedges on approximately 55% of its estimated total production. SilverBow has 217 million cubic feet per day (“MMcf/d”) (65% of guidance) of natural gas production hedged at an average floor price of $3.83 per million British thermal units (“MMBtu”) and at an average ceiling price of $4.21 per MMBtu. The Company has 12,775 Bbls/d (51% of guidance) of oil production hedged at an average floor price of $74.02 per barrel and at an average ceiling price of $76.46 per barrel. SilverBow has 4,400 Bbls/d (34% of guidance) of NGLs hedged at an average price of $25.92 per barrel. The hedged amounts are as of November 30, 2023 and are inclusive of swaps and collars.

CAPITAL STRUCTURE & LIQUIDITY

In connection with the closing the Chesapeake Transaction, SilverBow increased the borrowing base and aggregate elected commitment amount under the Company’s First Amended and Restated Senior Secured Revolving Credit Agreement, dated as of April 19, 2017, and amended by the Eleventh Amendment as of November 30, 2023 (the “Credit Facility”), among the Company, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent for the lenders from $775 million to $1.2 billion. Further, SilverBow issued and sold under the Company’s Note Purchase Agreement, dated as of December 15, 2017, and amended by the Fourth Amendment as of November 30, 2023 (the “Note Purchase Agreement”) an additional $350 million principal amount of second lien notes, resulting in $500 million aggregate principal amount of second lien notes outstanding. Additionally, the Company extended the maturity date of its second lien notes from December 15, 2026 to December 15, 2028 and modified certain other terms of the Note Purchase Agreement.

As of November 30, 2023, the Company had $449 million of undrawn capacity and approximately $15 million of cash resulting in approximately $464 million of liquidity.

INVESTOR PRESENTATION AND OTHER DETAILS

SilverBow has posted a presentation under the “Investor Relations” section of the Company’s website, www.sbow.com. Investors are encouraged to access for additional details and information.

ABOUT SILVERBOW RESOURCES, INC.

SilverBow Resources, Inc. (NYSE: SBOW) is a Houston-based energy company actively engaged in the exploration, development and production of oil and gas in the Eagle Ford Shale and Austin Chalk in South Texas. With over 30 years of history operating in South Texas, the Company possesses a significant understanding of regional reservoirs that it leverages to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

FORWARD-LOOKING STATEMENTS

This release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements represent management’s expectations or beliefs concerning future events, and it is possible that the results described in this release will not be achieved. These forward-looking statements are based on current expectations and assumptions and are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this press release, including those regarding our strategy, the benefits of the Chesapeake Transaction, future operations, guidance and outlook, financial position, well expectations and drilling plans, estimated production levels, expected oil and natural gas pricing, future free cash flow, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” ”guidance,” “outlook,” “expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, risks and uncertainties discussed in the Company’s reports filed with the Securities and Exchange Commission. All forward-looking statements speak only as of the date of this news release. You should not place undue reliance on these forward-looking statements.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this release or to reflect the occurrence of unanticipated events, except as required by law.

NON-GAAP MEASURES

This release contains forward-looking free cash flow, a non-GAAP measure. Free cash flow is calculated as EBITDA plus (less) monetized derivative contracts, cash interest expense, capital expenditures and current income tax (expense) benefit. EBITDA is defined as net income (loss) plus (less) depreciation, depletion and amortization, accretion of asset retirement obligations, interest expense, impairment of oil and natural gas properties, net losses (gains) on commodity derivative contracts, amounts collected (paid) for commodity derivative contracts held to settlement, income tax expense (benefit); and share-based compensation expense. The Company believes that free cash flow is useful to investors and analysts because it assists in evaluating SilverBow’s operating performance, and the valuation, comparison, rating and investment recommendations of companies within the oil and gas industry. SilverBow uses this information as one of the bases for comparing its operating performance with other companies within the oil and gas industry. The Company has provided forward-looking free cash flow in this release; however, SilverBow is unable to provide a quantitative reconciliation of these forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP measure because the items necessary to estimate such forward-looking GAAP measure are not accessible or estimable at this time without unreasonable efforts. The reconciling items in future periods could be significant.

 

Jeff Magids
Vice President of Finance & Investor Relations
(281) 874-2700, (888) 991-SBOW

Source: SilverBow Resources, Inc.

View all news

October 27, 2023

Nasdaq


HOUSTON – Exxon Mobil Corp XOM.N on Friday posted a $9.1 billion third-quarter profit, about a 54% drop from record earnings a year ago but up from the prior quarter as oil prices recovered. Earnings at the largest U.S. oil producer have benefited from higher crude oil prices compared to the previous quarter and demand for gasoline and diesel.

 

Exxon posts $9.1 billion net, down from year-ago, up 15% from Q2- oil and gas 360

Source: Reuters

Wall Street this month trimmed its third-quarter outlook after the company pointed to weaker chemical profits and refining margins.

Exxon’s buoyant performance has led to two all-stock deals: for shale rival Pioneer Natural Resources and for carbon pipeline operator Denbury, both struck as shares traded near an all-time record.

Third-quarter profit was $2.25 a share compared with $4.68 in the same quarter a year ago when oil and gas prices climbed following Russia’s invasion of Ukraine.

The latest quarter’s results benefited from global oil prices that averaged $85.92 per barrel in the quarter, from $77.73 in the second quarter, according to LSEG data.

The results were aided by higher oil and fuel prices, but damped by Exxon’s chemical business, which was hit by higher raw materials costs. Chemical Products third-quarter earnings were $249 million, down from $828 million in the second quarter.

Its cash reserves continued to build, up by 10% over the second quarter’s to $33 billion.

“We feel really good about our cash balance,” said Chief Financial Officer Kathryn Mikells said in an interview. “It puts us in a good position to ultimately ensure we have the flexibility we need when eventually the commodity cycle turns against us.”

Mikells said the company is keeping unaltered its 3.7 million boepd production target for 2023. It is also on track to distribute $17.5 billion in buybacks this year.

Exxon in the third quarter achieved a target to reduce its costs by year end by $9 billion compared to 2019.

Exxon beat a quarter earlier a $9 billion year-end cost saving target versus 2019. The oil producer also placed its full-year capital expenditures at the top end of its $23 billion to $25 billion guidance.

The company has been selling assets around the world as it focuses on more lucrative projects in the U.S. shale and in South America Guyana and it recently put its Italy refinery up for sale.

 

Investing


HOUSTON – Chevron (NYSE:CVX) posted a third-quarter profit that missed Wall Street estimates by a wide margin, sending its share price down in pre-market trading. Oil company earnings have slumped from record year-ago levels as crude prices eased and higher costs crimped refining and chemical profits. Results remain strong by historical standards but are well off year-ago levels.

Chevron's third-quarter profit slumps, shares fall 5% on earnings miss- oil and gas 360

Source: Reuters

The company earned $6.5 billion, down from $11.2 billion in the same period last year. Adjusted profit was $3.05 a share, compared to analysts’ expected $3.75 per share, according to LSEG data.

The earnings miss came after Chevron had warned in the second quarter that maintenance in its oil and gas production and refining businesses would hurt results. It also suffered a setback in a Kazakhstan project with a delay of about six months in expanding oil and gas production at its Tengizchevroil operation.

Shares fell 5.4% to $146.40 in early trading.

Exxon (NYSE:XOM) and TotalEnergies (EPA:TTEF) also posted lower third-quarter results on weaker crude oil and refining profits with Exxon’s profit down 54% and TotalEnergies’ off 35%.

Chevron agreed to buy U.S. rival Hess Corp (NYSE:HES) for $53 billion in an all-stock deal that expands its shale and deepwater oil production and reserves.

In addition to Hess, it acquired U.s. shale oil and gas producer PDC Energy (NASDAQ:PDCE) and a majority stake in ACES Delta, a U.S. hydrogen storage firm.

“It is going to be a rough day for CVX shareholders,” wrote RBC analyst Biraj Borkhataria, who described the earnings shortfall as “disappointing,” but blamed it on non-recurring items.

Capital expenditures during the quarter rose more than 50% to $4.7 billion, in part on the acquisition of ACES Delta. Total cost for the Tengizchevroil expansion project is expected to rise by $1 billion.

Profit from pumping oil and gas fell about 38% to $5.76 billion in the quarter from $9.3 billion a year ago.

Overall, volumes rose 4% to 3.15 million barrels of oil and gas per day (boed) on the PDC Energy deal, which increased the production of less-lucrative natural gas by 25%. Chevron pumped 3.03 million boed a year ago.

Oil prices recently rebounded from a mid-year slump as tighter supplies drove up crude prices. The company’s cash flow from operations fell to $9.7 billion from $15.3 billion a year ago.

Its refining business posted an operating profit of $1.68 billion, down from $2.53 billion a year ago on sharply lower results outside the United States. Gains by its U.S. refining business were offset by weakness overseas, where margins and inputs fell.

May 16, 2023

Oil and Gas 360


HOUSTON, TX / ACCESSWIRE / May 15, 2023 / PEDEVCO Corp. (NYSE American:PED) (“PEDEVCO” or the “Company”), an energy company engaged in the acquisition and development of strategic, high growth energy projects in the U.S., today announced its financial results for the three months ended March 31, 2023 and provided an operations update.

PEDEVCO announces Q1 2023 financial results and operations update- oil and gas 360

Key Highlights Include:

  • Produced an average of approximately 1,428 barrels of oil equivalent per day (“BOEPD”) (80.4% oil) in the three months ended March 31, 2023 (“Q1 2023”), with Q1 2023 revenue of $8.2 million increasing 15% over revenue earned during the three months ended March 31, 2022 (“Q1 2022”).
  • Reported operating income of $1.6 million and operating expenses (inclusive of general and administrative expenses, depreciation, depletion and amortization expenses and lease operating expenses) of $6.5 million, increasing 30% and 12%, respectively, from Q1 2022.
  • Reported net income of $1.8 million, or $0.02 per basic and diluted share outstanding, compared to net income of $1.3 million, or $0.02 per basic and diluted share outstanding, in Q1 2022.
  • Adjusted EBITDA, a non-GAAP financial measure (discussed in greater detail below), increased 28% to $4.9 million, compared to $3.8 million in Q1 2022.
  • Reported cash and cash equivalents (including $3.55 million in restricted cash) of $17.7 million as of March 31, 2023, and zero debt.
  • Production growth in Q1 2023 attributable to commencement of production from fourteen new non-operated wells in the D-J Basin, including 6 wells in the Barracuda Unit in which the Company holds an approximate 35.8% working interest which began producing in December 2022, and eight wells in the Ross Unit in which the Company holds an approximate 4.7% working interest which were turned in line (TIL) in early February 2023 and should continue to increase production into the second quarter of 2023.
  • Currently estimating to participate in seven additional non-operated horizontal Niobrara wells in the D-J Basin in the second half of 2023 where the Company holds an approximate 18% working interest. Permits are in place; however, the Company has not yet been AFE’d by the operating partner.
  • Currently permitting and securing vendor commitments to drill and complete 4 operated horizontal Niobrara wells in the D-J Basin where the Company holds an approximate 70% working interest, with drilling expected to commence in late 2023 and into early 2024.

J. Douglas Schick, President of the Company, stated, “We are pleased with the results from our 2022 non-operated development program which we began to see in Q1 2023. This program has helped to deliver strong operational and financial results to our shareholders in the quarter, including an increase in production, cash flow, earnings per share, and Adjusted EBITDA even as oil prices were lower for Q1 2023 compared to Q1 2022, all while maintaining zero debt and controlling G&A expenses. We expect to continue to see meaningful production growth through Q2 2023 as production from the fourteen non-operated wells in which we participated in during 2022 are now all online. We seek to continue to leverage our strong cash position and zero debt to continue to grow our production, revenue, and profit, as well as increase our asset base for the benefit of our shareholders.”

Financial Summary:

For the three months ended March 31, 2023, we reported a net income of $1.8 million, or $0.02 per basic and diluted share outstanding, compared to net income of $1.3 million, or $0.02 per basic and diluted share outstanding in Q1 2022.

The increase in net income of $0.5 million, when comparing the current period to the prior year’s period, was primarily due to a $1.2 million increase in combined net revenues and interest income offset by a $0.7 million increase in total operating expenses (discussed in more detail below).

We reported operating expenses in Q1 2023 of $6.5 million, compared to $5.8 million in Q1 2022. The increase of $0.7 million was primarily due to a $0.1 million increase in lease operating expenses due to planned activity for the beginning of the 2023 year to move forward the timing of operational and facility improvements, and equipment maintenance, and a $0.7 million increase in depreciation, depletion, amortization and accretion expense due to an increased production and a decrease in general and administrative expenses of $0.1 million in the current period when compared to the prior period.

Adjusted EBITDA, a non-GAAP financial measure (discussed in greater detail below), increased 28% to $4.9 million in Q1 2023, compared to $3.8 million in Q1 2022.

Cash and cash equivalents was $17.7 million as of March 31, 2023 (including $3.55 million in restricted cash), compared with $33.0 million as of December 31, 2022 (including $3.55 million in restricted cash), which decrease was due largely to increased capital spending related to our drilling and completion activities.

Production, Prices and Revenues:

Production for Q1 2023 was 128,514 barrels of oil equivalent (“Boe”), comprised of 103,329 barrels of oil, 87,658 million cubic feet (“Mcf”) of natural gas, and 10,575 Boe of natural gas liquids (“NGLs”). Liquids production comprised 88.6% of total production in the quarter.

Our average realized crude oil sales price in Q1 2023 was $72.19 per barrel, average realized natural gas price was $5.75 per Mcf, and average realized NGL sales price was $18.90 per barrel. Our combined average realized sales price for the quarter was $63.52 per Boe, which was a decrease of 13% compared with $73.36 per Boe in Q1 2022.

Total crude oil, natural gas and NGL revenues for Q1 2023 increased $1.1 million, or 15%, to $8.2 million, compared to $7.1 million for the same period a year ago, due to a favorable volume variance of $2.0 million offset by an unfavorable price variance of $0.9 million. The increase in production volume is related to the positive performance from our participation in 14 non-operated wells in the D-J Basin Asset (six of which began producing in late 2022 and eight of which began producing in the three months ended March 31, 2023), combined with maintaining relatively flat production declines from our existing operated Permian Basin and D-J Basin Assets.

Lease Operating Expenses (“LOE”):

Total LOE for Q1 2023 was $2.5 million compared to total LOE for Q1 2022 of $2.4 million. The $0.1 million increase was primarily due to planned activity for the beginning of the 2023 year to move forward the timing of operational and facility improvements, and equipment maintenance.

Depreciation, Depletion, Amortization and Accretion (“DD&A”):

DD&A increased from $1.9 million in Q1 2022 to $2.6 million in Q1 2023. The $0.7 million increase was primarily the result of an increase in production (noted above) in the current period when compared to the prior period.

General and Administrative Expenses (“G&A”):

There was a nominal decrease in G&A expenses (excluding share-based compensation) in Q1 2023 compared to Q1 2022 as the Company continues to strive to contain costs and remain within budget from period to period.

Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, decreased nominally due to the forfeiture of certain employee stock-based options and nonvested restricted shares due to certain voluntary employee terminations. Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.

Interest Income and Other Expense:

We earned $98,000 in interest from our interest-bearing cash accounts, for which interest rates have increased in the current period, compared to the prior period. Other income of $35,000 in Q1 2023 was primarily related to the sale of used pipe offset by a vendor dispute settlement in the prior period.

Working Capital and Liquidity:

At March 31, 2023, our total current assets of $20.1 million exceeded our total current liabilities of $6.8 million, resulting in a working capital surplus of $13.3 million, while at December 31, 2022, our total current assets of $32.1 million exceeded our total current liabilities of $17.0 million, resulting in a working capital surplus of $15.1 million. The $1.8 million decrease in our working capital surplus was primarily related to cash used to fund our current capital drilling budget.

Operations Update:

We are currently applying for permits and securing vendor commitments to drill and complete 4 operated horizontal Niobrara wells in the D-J Basin where we hold an approximate 70% working interest, with drilling expected to commence in late 2023 and into early 2024. In addition, based on discussions with our non-operating partners in the D-J Basin, we currently plan to participate in an additional 7 non-operated horizontal Niobrara wells in the D-J Basin in the second half of 2023 where we hold an approximate 18% working interest. Permits for this project are in place; however, we have not yet been AFE’d by the operating partner. Contingent upon availability of funds related to the timing of these D-J Basin Asset projects planned in 2023, we may also seek to drill and complete an additional 3 horizontal San Andres wells on our Permian Basin Asset in 2023. We have permits for these San Andres wells, which we plan to drill and complete if either of our D-J Basin Asset operated or non-operated projects gets pushed past early 2024.

More information regarding our operating results for the three months ended March 31, 2023, including our full financial statements and footnotes, can be found in our Quarterly Report on Form 10-Q which was filed earlier today with the Securities and Exchange Commission and is available at www.sec.gov.

About PEDEVCO Corp.

PEDEVCO Corp. (NYSE American: PED), is a publicly-traded energy company engaged in the acquisition and development of strategic, high growth energy projects in the United States. The Company’s principal assets are its Permian Basin Asset located in the Northwest Shelf of the Permian Basin in eastern New Mexico, and its D-J Basin Asset located in the D-J Basin in Weld and Morgan Counties, Colorado, and southern Wyoming. PEDEVCO is headquartered in Houston, Texas.

Use of Non-GAAP Financial Information

This earnings release discusses EBITDA and Adjusted EBITDA which are presented as supplemental measures of the Company’s performance. These measurements are not recognized in accordance with generally accepted accounting principles (GAAP) and should not be viewed as an alternative to GAAP measures of performance. EBITDA represents net income before interest, taxes, depreciation and amortization. Adjusted EBITDA is defined as EBITDA, less share-based compensation. EBITDA and Adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and Adjusted EBITDA are also frequently used by analysts, investors and other interested parties to evaluate companies in our industry. We use EBITDA and Adjusted EBITDA as supplements to GAAP measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA and Adjusted EBITDA do not reflect cash expenditures, future requirements for capital expenditures, or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments. For example, although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Additionally, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in isolation, or as substitutes for analysis of the Company’s results as reported under GAAP. The Company’s presentation of these measures should not be construed as an inference that future results will be unaffected by unusual or nonrecurring items. We compensate for these limitations by providing a reconciliation of each of these non-GAAP measures to the most comparable GAAP measure. We encourage investors and others to review our business, results of operations, and financial information in their entirety, not to rely on any single financial measure, and to view these non-GAAP measures in conjunction with the most directly comparable GAAP financial measure. For more information on these non-GAAP financial measures, please see the section titled “Reconciliation of Net Income (Loss) attributable to PEDEVCO Corp., to Earnings before Interest, Taxes, Depreciation and Amortization (EBITDA) and Adjusted EBITDA”, included at the end of this release.

Cautionary Statement Regarding Forward Looking Statements

This press release may contain forward-looking statements, including information about management’s view of PEDEVCO’s future expectations, plans and prospects, within the meaning of the federal securities laws, including the safe harbor provisions under The Private Securities Litigation Reform Act of 1995 (the “Act”). In particular, when used in the preceding discussion, the words “may,” “could,” “expect,” “intend,” “plan,” “seek,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “continue,” “likely,” “will,” “would” and variations of these terms and similar expressions, or the negative of these terms or similar expressions are intended to identify forward-looking statements within the meaning of the Act and such laws, and are subject to the safe harbor created by the Act and applicable laws. Any statements made in this news release other than those of historical fact, about an action, event or development, are forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors, which may cause the results of PEDEVCO and its subsidiaries to be materially different than those expressed or implied in such statements. The forward-looking statements include projections and estimates of the Company’s corporate strategies, future operations, development plans and programs, including the costs thereof, drilling locations, estimated oil, natural gas and natural gas liquids production, price realizations, projected operating, general and administrative and other costs, projected capital expenditures, efficiency and cost reduction initiative outcomes, statements regarding future production, costs and cash flows, liquidity and our capital structure. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, developing and replacing oil and natural gas reserves, risks of our operations not being profitable or generating sufficient cash flow to meet our obligations; risks relating to the future price of oil, natural gas and NGLs; risks related to the status and availability of oil and natural gas gathering, transportation, and storage facilities; risks related to changes in the legal and regulatory environment governing the oil and gas industry, and new or amended environmental legislation and regulatory initiatives; risks relating to crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries; technological advancements; changing economic, regulatory and political environments in the markets in which the Company operates; general domestic and international economic, market and political conditions, including the military conflict between Russia and Ukraine and the global response to such conflict; actions of competitors or regulators; the potential disruption or interruption of the Company’s operations due to war, accidents, political events, severe weather, cyber threats, terrorist acts, or other natural or human causes beyond the Company’s control; risks related to the need for additional capital to complete future acquisitions, conduct our operations, and fund our business on favorable terms, if at all, the availability of such funding and the costs thereof; risks related to the limited control over activities on properties we do not operate and the speculative nature of oil and gas operations in general; risks associated with the uncertainty of drilling, completion and enhanced recovery operations; risks associated with illiquidity and volatility of our common stock, dependence upon present management, the fact that Dr. Simon Kukes, our CEO and member of the Board, beneficially owns a majority of our common stock, and our ability to maintain the listing of our common stock on the NYSE American; pandemics, governmental responses thereto, economic downturns and possible recessions caused thereby; inflationary risks and recent increased interest rates, and the risks of recessions and economic downturns caused thereby or by efforts to reduce inflation; risks related to military conflicts in oil producing countries; changes in economic conditions; limitations in the availability of, and costs of, supplies, materials, contractors and services that may delay the drilling or completion of wells or make such wells more expensive; the amount and timing of future development costs; the availability and demand for alternative energy sources; regulatory changes, including those related to carbon dioxide and greenhouse gas emissions; and others that are included from time to time in filings made by PEDEVCO with the Securities and Exchange Commission, many of which are beyond our control, including, but not limited to, in the “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” sections of its Form 10-Ks and Form 10-Qs and in its Form 8-Ks, which it has filed, and files from time to time, with the U.S. Securities and Exchange Commission, including, but not limited to its Annual Report on Form 10-K for the year ended December 31, 2022 and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2023. These reports are available at www.sec.gov. The Company cautions that the foregoing list of important factors is not complete. All subsequent written and oral forward-looking statements attributable to the Company or any person acting on behalf of the Company are expressly qualified in their entirety by the cautionary statements referenced above. Other unknown or unpredictable factors also could have material adverse effects on PEDEVCO’s future results and/or could cause our actual results and financial condition to differ materially from those indicated in the forward-looking statements. The forward-looking statements included in this press release are made only as of the date hereof. PEDEVCO cannot guarantee future results, levels of activity, performance or achievements. Accordingly, you should not place undue reliance on these forward-looking statements. We undertake no obligation to update publicly any of these forward-looking statements to reflect actual results, new information or future events, changes in assumptions or changes in other factors affecting forward-looking statements, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. The internal projections, expectations, or beliefs underlying our 2023 capital budget are subject to change in light of numerous factors, including, but not limited to, the prevailing prices of oil and gas, actions taken by businesses and governments, ongoing results, prevailing economic circumstances, commodity prices, and industry conditions and regulations.

PEDEVCO CORP.
CONSOLIDATED BALANCE SHEETS
(amounts in thousands, except share and per share data)

March 31, 2023 December 31,
(Unaudited) 2022
Assets
Current assets:
Cash and cash equivalents
$ 14,139 $ 29,430
Accounts receivable – oil and gas
5,788 2,430
Prepaid expenses and other current assets
149 249
Total current assets
20,076 32,109
Oil and gas properties:
Oil and gas properties, subject to amortization, net
82,692 79,372
Oil and gas properties, not subject to amortization, net
1,500 775
Total oil and gas properties, net
84,192 80,147
Operating lease – right-of-use asset
45 71
Other assets
3,821 3,783
Total assets
$ 108,134 $ 116,110
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable
$ 3,683 $ 1,556
Accrued expenses
1,375 13,835
Revenue payable
1,000 1,018
Operating lease liabilities – current
51 81
Asset retirement obligations – current
658 472
Total current liabilities
6,767 16,962
Long-term liabilities:
Asset retirement obligations, net of current portion
2,628 2,689
Total liabilities
9,395 19,651
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.001 par value, 200,000,000 shares authorized; 87,040,267 and 85,790,267 shares issued and outstanding, respectively
87 86
Additional paid-in capital
223,631 223,114
Accumulated deficit
(124,979 ) (126,741 )
Total shareholders’ equity
98,739 96,459
Total liabilities and shareholders’ equity
$ 108,134 $ 116,110

PEDEVCO CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(amounts in thousands, except share and per share data)

Three Months Ended March 31,
2023 2022
Revenue:
Oil and gas sales
$ 8,164 $ 7,090
Operating expenses:
Lease operating costs
2,466 2,356
Selling, general and administrative expense
1,488 1,592
Depreciation, depletion, amortization and accretion
2,581 1,886
Total operating expenses
6,535 5,834
Operating income
1,629 1,256
Other income:
Interest income
98 3
Other income
35 80
Total other income
133 83
Net income
$ 1,762 $ 1,339
Earnings per common share:
Basic
$ 0.02 $ 0.02
Diluted
$ 0.02 $ 0.02
Weighted average number of common shares outstanding:
Basic
86,720,823 86,066,070
Diluted
86,720,823 86,066,070

PEDEVCO CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)

Three Months Ended March 31,
2023 2022
Cash Flows From Operating Activities:
Net income
$ 1,762 $ 1,339
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion
2,581 1,886
Amortization of right-of-use asset
26 24
Share-based compensation expense
518 563
Changes in operating assets and liabilities:
Accounts receivable – oil and gas
(3,358 ) (2,188 )
Prepaid expenses and other current assets
100 109
Accounts payable
35 (94 )
Accrued expenses
136 (243 )
Revenue payable
(18 ) 19
Net cash provided by operating activities
1,782 1,415
Cash Flows From Investing Activities:
Cash paid for drilling and completion costs
(17,032 ) (5,508 )
Cash paid for vehicle
(41 )
Net cash used investing activities
(17,073 ) (5,808 )
Net decrease in cash, cash equivalents and restricted cash
(15,291 ) (4,093 )
Cash, cash equivalents and restricted cash at beginning of period
32,977 29,227
Cash, cash equivalents and restricted cash at end of period
$ 17,686 $ 25,134
Supplemental Disclosure of Cash Flow Information
Cash paid for:
Interest
$ $
Income taxes
$ $
Noncash investing and financing activities:
Change in accrued oil and gas development costs
$ 10,534 $ 173
Changes in estimates of asset retirement costs, net
$ 6 $ 45
Issuance of restricted common stock
$ 1 $ 1

Reconciliation of Net Income (Loss) attributable to PEDEVCO Corp., to Earnings before Interest, Taxes, Depreciation and Amortization (EBITDA) and Adjusted EBITDA* (in thousands)

Three Months Ended March 31,
2023 2022
Net income
$ 1,762 $ 1,339
Add (deduct)
Depreciation, depletion, amortization and accretion
2,581 1,886
EBITDA
4,343 3,225
Add (deduct)
Share-based compensation
518 563
Adjusted EBITDA
$ 4,861 $ 3,788

* EBITDA and Adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. See also “Use of Non-GAAP Financial Information”, above.

CONTACT:

PEDEVCO Corp.
(713) 221-1768
PR@pedevco.com

SOURCE: PEDEVCO Corp.

View source version on accesswire.com:
https://www.accesswire.com/755019/PEDEVCO-Announces-Q1-2023-Financial-Results-and-Operations-Update

March 14, 2023

Nasdaq


U.S. natural gas futures held near a one-week high on Tuesday on forecasts for more cold weather and higher heating demand this week than previously expected, a preliminary drop in daily output and near record amounts of gas flowing to liquefied natural gas (LNG) export plants.

US natgas futures hold near one-week high on colder forecasts- oil and gas 360

Source: Reuters

Weighing on prices were forecasts for less cold weather and lower heating demand next week than previously expected.

After soaring 7% on Monday, front-month gas futures NGc1 for April delivery remained unchanged at $2.607 per million British thermal units (mmBtu) at 8:09 a.m. EDT (1209 GMT) on Tuesday, putting the contract on track for its highest close since March 7 for a second day in a row.

The gas market has been extremely volatile in recent weeks as traders bet on the latest weather forecasts.

The front-month fell to a 28-month low below $2 per mmBtu in intraday trade on Feb. 22 on forecasts for warmer weather before jumping 9% on colder forecasts to settle at a five-week high above $3 just over a week later on March 3. It plunged 15% on March 6 on a warmer outlook.

Gas flows to LNG export plants have been on track to hit record highs since Freeport LNG‘s export plant in Texas exited an eight-month outage in February. The plant was shut due to a fire in June 2022.

Freeport LNG was on track to pull in 1.0 billion cubic feet per day (bcfd) of gas on Tuesday, up from 0.3 bcfd on Monday, according to data provider Refinitiv.

When operating at full power, Freeport LNG, the second-biggest U.S. LNG export plant, can turn about 2.1 bcfd of gas into LNG for export.

Federal regulators approved the restart of two of Freeport LNG’s three liquefaction trains (Trains 2 and 3) in February and the third train (Train 1) on March 8. Liquefaction trains turn gas into LNG.

Total gas flows to all seven of the big U.S. LNG export plants rose to an average of 13.1 bcfd so far in March from 12.8 bcfd in February. That would top the monthly record of 12.9 bcfd in March 2022, before the Freeport LNG facility shut.

The seven big U.S. LNG export plants, including Freeport LNG, can turn about 13.8 bcfd of gas into LNG.

SUPPLY AND DEMAND

Refinitiv said average gas output in the U.S. Lower 48 states rose to 98.7 bcfd so far in March from 98.2 bcfd in February. That compares with a monthly record of 99.9 bcfd in November 2022.

On a daily basis, however, output was on track to drop by 1.8 bcfd to a preliminary five-week low of 97.5 bcfd on Tuesday. That would be the biggest one-day output decline since late December. Energy traders said the decline was likely caused by freezing oil and gas wells in several producing basins, known as freeze-offs.

Meteorologists projected the weather in the Lower 48 states would remain mostly colder than normal through March 29 with the coldest days expected on Saturday and Sunday, March 18-19.

Even though the weather will be colder than normal over the next two weeks, temperatures were still rising with the coming of spring.

Refinitiv forecast U.S. gas demand, including exports, would slide from 120.1 bcfd this week to 119.5 bcfd next week. The forecasts for this week were higher than Refinitiv’s outlook on Monday, while its forecasts for next week were lower.

Milder winter weather so far this year has prompted utilities to leave more gas in storage than usual.

Gas stockpiles were about 22% above their five-year average (2018-2022) during the week ended March 3 and were expected to end about 24% above normal during the week ended March 10, according to federal data and analysts’ estimates. EIA/GASNGAS/POLL

March 2, 2023

BOE Report


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, ABMarch 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“).

Tamarack Valley Energy announces year-end 2022 reserves & financial results and provides operational update- oil and gas 360

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

Three months ended

Year ended

December 31,

December 31,

2022

2021

  % change

2022

2021

  % change

($ thousands, except per share)

Total oil, natural gas and processing revenue

423,760

243,184

74

1,459,154

701,051

108

Cash flow from operating activities

227,889

118,647

92

805,377

297,894

170

    Per share – basic

$ 0.42

$ 0.29

45

$ 1.75

$ 0.84

108

    Per share – diluted

$ 0.42

$ 0.29

45

$ 1.73

$ 0.83

108

Adjusted funds flow(1)

196,746

124,080

59

727,061

340,259

114

    Per share – basic

$ 0.36

$ 0.31

16

$ 1.58

$ 0.96

65

    Per share – diluted

$ 0.36

$ 0.30

20

$ 1.57

$ 0.94

67

Net income

50,441

140,448

(64)

345,198

390,508

(12)

    Per share – basic

$ 0.09

$ 0.35

(74)

$ 0.75

$ 1.10

(32)

    Per share – diluted

$ 0.09

$ 0.34

(74)

$ 0.74

$ 1.08

(31)

Net debt (1)

(1,356,570)

(463,284)

193

(1,356,570)

(463,284)

193

Capital expenditures(1),(3)

125,276

41,671

201

458,577

191,159

140

Weighted average shares outstanding (thousands)

   Basic

545,118

406,061

34

460,345

353,642

30

   Diluted

549,062

413,944

33

464,276

360,779

29

Share Trading

High

$ 5.60

$ 3.95

42

$ 6.48

$ 3.95

64

Low

$ 3.92

$ 3.08

27

$ 3.28

$ 1.25

162

Average daily share trading volume (thousands)

3,419

3,290

4

3,773

2,888

31

Average daily production

   Light oil (bbls/d)

17,382

18,487

(6)

17,423

15,670

11

   Heavy oil (bbls/d)

31,328

5,616

458

15,768

4,613

242

   NGL (bbls/d)

4,241

3,899

9

3,888

3,408

14

   Natural gas (mcf/d)

68,355

74,291

(8)

67,221

65,226

3

   Total (boe/d)

64,344

40,384

59

48,283

34,562

40

Average sale prices

   Light oil ($/bbl)

103.37

88.59

17

115.47

78.64

47

   Heavy oil, net of blending expense ($/bbl)

71.36

71.69

85.40

64.56

32

   NGL ($/bbl)

50.53

55.09

(8)

54.66

41.77

31

   Natural gas ($/mcf)

4.89

5.09

(4)

6.15

3.70

66

   Total ($/boe)

71.19

65.21

9

82.54

55.38

49

Operating netback ($/Boe)

   Average realized sales, net of blending expense

71.19

65.21

9

82.54

55.38

49

   Royalty expenses

(15.07)

(9.50)

59

(16.01)

(8.10)

98

   Net production and transportation expenses(1)

(14.19)

(10.84)

31

(13.23)

(10.77)

23

Operating field netback ($/Boe)(1)

41.93

44.87

(7)

53.30

36.51

46

   Realized commodity hedging gain (loss)

0.31

(8.25)

(104)

(3.52)

(6.40)

(45)

Operating netback ($/Boe)(1)

42.24

36.62

15

49.78

30.11

65

Adjusted funds flow ($/Boe)(1)

33.24

33.40

41.26

26.97

53


Reserves Snapshot by Category

PDP

TP

TPP

Total Reserves (mboe)(5)

75,744

135,066

242,191

Reserves Added (mboe)(6)

37,077

48,556

77,882

Reserves Replacement

210 %

276 %

442 %

NPV10 Before Tax ($mm)

$1,842

$2,852

$4,975


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

(mboe)

December 31,

2022(5)

December 31,

2021(5)

% Change

PDP

75,744

56,290

35 %

TP

135,066

104,133

30 %

TPP

242,191

181,932

33 %


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 LakeClearwater and enhanced oil recovery projects to enhance return of capital to shareholders. The following table summarizes our 2023 annual guidance(7).

Capital Budget ($mm)(3)

$425 – $475

Annual Average Production (boe/d)(7)

68,000 – 72,000

Average Oil & NGL Weighting

81% – 83%

Expenses:

Royalty Rate (%)

19% – 21%

Operating ($/boe)

$9.00 – $9.50

Transportation ($/boe)(8) 

$3.50 – $4.00

General and Administrative ($/boe)(9)

$1.25 – $1.35

Interest ($/boe)

$3.80 – $4.00

Taxes (%)

10% – 12%

Leasing Expenditures ($mm)

$3.5 – $4.5


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 ClearwaterTamarack 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.

Investor Call Tomorrow

9:00 AM MDT (11:00 AM EDT)

Tamarack will host a webcast at 9:00 AM MDT (11:00 AM EDT) on Thursday, March 2, 2023 to discuss the year-end reserves, financial results and an operational update. Participants can access the live webcast via this link or through links provided on the Company’s website. A recorded archive of the webcast will be available on the Company’s website following the live webcast.


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)

Reserves Category

Crude
Oil
Lt. & Med.
Gross(15)
(MBbl)

Crude
Oil
Lt. & Med.
Net(15)
(MBbl)

Crude
Oil
Heavy
Gross
(MBbl)

Crude
Oil
Heavy
Net
(MBbl)

Conven-
tional
Natural
Gas
Gross
(MMcf)(16)

Conven-
tional
Natural
Gas
Net
(MMcf)(16)

Natural
Gas
Liquids
Gross
(MBbl)

Natural
Gas
Liquids
Net
(MBbl)

Total
Gross
(MBoe)

Total
Net
(Mboe)

Proved:

Developed Producing 

25,098

19,787

24,266

19,691

115,876

104,129

7,069

5,691

75,744

62,524

Developed Non-Producing 

797

730

1,313

1,100

3,686

3,282

109

80

2,834

2,458

Undeveloped 

23,246

18,893

18,557

15,976

64,100

57,446

4,001

3,260

56,488

47,703

Total Proved

49,141

39,410

44,136

36,767

183,662

164,856

11,179

9,031

135,066

112,684

Probable

38,169

29,472

39,035

31,901

130,545

115,291

8,164

6,419

107,126

87,007

Total Proved plus Probable(17)

87,310

68,881

83,171

68,669

314,208

280,148

19,343

15,450

242,191

199,692


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

Reserves Category

0 %($000)

5 %($000)

10 %($000)

15 %($000)

20 %($000)

Unit Value
Before Tax
Discounted
at
10%/Year(19)
($/Boe) 

Unit Value
Before Tax
Discounted
at
10%/Year(19)
($/Mcfe) 

Proved:

Developed Producing 

2,267,461

2,029,788

1,841,795

1,691,893

1,570,059

29.46

4.91

Developed Non-Producing 

103,748

87,279

75,539

66,845

60,175

30.73

5.12

Undeveloped 

1,567,147

1,193,320

934,776

749,710

612,823

19.60

3.27

Total Proved

3,938,356

3,310,386

2,852,110

2,508,448

2,243,058

25.31

4.22

Probable

3,837,607

2,770,033

2,123,058

1,698,794

1,402,842

24.40

4.07

Total Proved plus Probable(17)

7,775,962

6,080,420

4,975,168

4,207,241

3,645,900

24.91

4.15


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

Total Proved
(Mboe)

Total Probable
(Mboe)

Total Proved + Probable
(Mboe)

December 31, 2021   

104,133

77,799

181,932

Discoveries 

0

0

0

Extensions & Improved Recovery(20) 

14,783

7,675

22,459

Technical Revisions 

994

(8,813)

(7,819)

Acquisitions 

36,199

33,241

69,440

Dispositions 

(5,659)

(3,367)

(9,026)

Economic Factors 

2,240

590

2,830

Production 

(17,623)

0

(17,623)

December 31, 2022(17)

135,066

107,126

242,191


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.

Year

Total Proved
Reserves
($000)

Total Proved Plus
Probable Reserves
($000)

2023

243,873

342,424

2024

325,320

449,859

2025

235,577

397,175

2026 and Subsequent

193,615

397,952

Total 

998,385

1,587,410

10% Discounted 

832,446

1,300,876


Finding, Development & Acquisition Costs

2022

Three-Year Average

(amounts in $000s except as noted)

TP

TPP

TP

TPP

FD&A costs, including FDC(21)(22)

Exploration and development capital expenditures (23)(24)(25)

389,120

389,120

227,941

227,941

Acquisitions, net of dispositions(26)

1,758,182

1,758,182

860,224

860,224

Total change in FDC

374,870

621,784

199,945

294,887

Total FD&A capital, including change in FDC(17)

2,522,172

2,769,086

1,288,110

1,383,051

Reserve additions, including revisions – Mboe(5)

18,017

17,470

10,525

8,937

Acquisitions, net of dispositions – Mboe(5)

30,539

60,413

27,968

50,683

Total FD&A Reserves(17)

48,556

77,883

38,493

59,620

F&D costs, including FDC – $/boe

51.94

35.55

33.46

23.20

Acquisition costs, net of dispositions – $/boe

31.59

37.05

24.43

27.25

FD&A costs, including FDC – $/boe

63.95

35.12

36.86

22.48


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 LakeClearwater 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

AECO

the natural gas storage facility located at Suffield, Alberta connected to TC Energy’s Alberta System

ARO

asset retirement obligation; may also be referred to as decommissioning obligation

bbls

barrels

bbls/d

barrels per day

boe

barrels of oil equivalent

boe/d

barrels of oil equivalent per day

bopd

barrels of oil per day

GJ

gigajoule

IFRS

International Financial Reporting Standards as issued by the International Accounting Standards Board

IP30

average production for the first 30 days that a well is onstream

mcf

thousand cubic feet

mcf/d

thousand cubic feet per day

MM

Million

mmcf/d

million cubic feet per day

MSW

Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil in Western Canada

NGL

Natural gas liquids

PDP

Proved developed producing reserves

TP

Total proved reserves

TPP

Total proved plus probable reserves

WCS

Western Canadian select, the benchmark for conventional and oil sands heavy production at Hardisty in Western Canada

WTI

West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade

Reader Advisories

Notes to Press Release

(1)   

See “Specified Financial Measures”

(2)     

Q4 2022 production guidance of 62,000-64,000 boe/d was comprised of 16,500-17,500 bbl/d light and medium oil, 35,000-37,000 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 73,000-78,000 mcf/d natural gas.

Q4 2022 production of 64,344 boe/d was comprised of 17,382 bbl/d light and medium oil, 31,328 bbl/d heavy oil, 4,241 bbl/d NGL and 68,355 mcf/d natural gas.

2022 yearly production of 48,283 boe/d was comprised of 17,423 bbl/d light and medium oil, 15,768 bbl/d heavy oil, 3,888 bbl/d NGL and 67,221 mcf/d natural gas.

(3) 

Capital expenditures include exploration and development capital, ESG initiatives, facilities land and seismic but exclude asset acquisitions and dispositions as well as ARO. Capital budget includes exploration and development capital, ARO, ESG initiatives, facilities land and seismic but excludes asset acquisitions and dispositions. The key difference between these two metrics is the inclusion (capital budget) or exclusion (capital expenditures) of ARO.   

(4) 

Realized before-tax net present value of reserve, discounted at 10%

(5) 

Reserves are Company Gross Reserves which exclude royalty volumes

(6)   

Reserves Added takes the difference in reserves year-over-year plus the production for the year

(7)   

Target production is comprised of 16,500-17,500 bbl/d light and medium oil, 35,000-37,000 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 73,000-78,000 mcf/d natural gas. Annual guidance numbers are based on 2023 average pricing assumptions of: US$80.00/bbl WTI; US$22.00/bbl WCS; US$3.00/bbl MSW; $4.00/GJ AECO; and $1.3200 CAD/USD.

(8)   

Transportation expense differs from the previously released 2023 guidance due to a change in the classification of pipeline tariffs in our corporate model. Some pipeline tariffs were originally included as a revenue deduction, are now included as transportation expense.

(9)   

G&A noted excludes the effect of cash settled stock-based compensation

(10) 

Production of 12,500 boe/d is comprised of approximately 11,800 bbl/d heavy oil, 100 bbl/d NGL and 3,600 mcf/d natural gas

(11) 

Production of 1,900 boe/d is comprised of approximately 1,900 bbl/d heavy oil

(12) 

Current production of 16,300 boe/d is comprised of approximately 15,390 bbl/d heavy oil, 110 bbl/d NGL and 4,800 mcf/d natural gas while production at acquisition of 15,100 boe/d is comprised of approximately 14,260 bbl/d heavy oil, 90 bbl/d NGL and 4,500 mcf/d natural gas

(13) 

Production of 1,900 boe/d is comprised of approximately 1,200 bbl/d light and medium oil, 125 bbl/d NGL and 3,450 mcf/d natural gas

(14) 

Production of 16,900 boe/d is comprised of approximately 9,600 bbl/d light and medium oil, 2,300 bbl/d NGL and 30,000 mcf/d natural gas

(15) 

Tight oil included in the light & medium crude oil product type represents less than 6.5% of any reserves category

(16) 

Conventional natural gas amounts include coal bed methane, in amounts less than 0.3% of any reserves category

(17) 

Columns may not add due to rounding

(18) 

Unit values based on Company net interest reserves

(19) 

The prices used to estimate net present values are based on the 3-Consultant Average Forecast Pricing

(20) 

Reserves additions under Infill Drilling, Improved Recovery and Extensions are combined and reported as “Extensions and Improved Recovery”

(21) 

FDC as per Reserve Report based on the 3-Consultant Average Forecast Pricing

(22)

While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above.

(23)

The calculation of FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

(24)

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

(25)

The capital expenditures also exclude capitalized administration costs.

(26)

Includes capital spent in 2022 to develop the assets acquired during 2022 as well as major land acquisitions in the Peavine and Seal areas.

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.

February 24, 2023

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

February 23, 2023

Oil Price


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.

 

U.S. LNG giant sees revenues more than double in 2022- oil and gas 360

Source: Reuters

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

Permian Resources Corporation (“Permian Resources” or the “Company”) …

Announces $1 Billion Share Repurchase Authorization and Declares Fixed-plus-Variable Dividend to …

DENVER, Feb. 22, 2023 (GLOBE NEWSWIRE) — PDC Energy, Inc. (“PDC” or the “Co…

Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today…

Oil and Gas 360


DENVERFeb. 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:

 

SM Energy reports 2022 results and 2023 operating plan- oil and gas 360

  • 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

MMBoe

Estimated proved reserves year-end 2021

492.0

Revisions – infill and performance

92.1

Production

(53.0)

Revisions – 5-year rule

(19.9)

Reserve additions

16.7

Revisions – price

9.5

Estimated proved reserves year-end 2022

537.4

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 AND FULL YEAR 2022 RESULTS

PRODUCTION BY OPERATING AREA

Fourth Quarter 2022

Midland Basin

South Texas

Total

Oil (MBbl / MBbl/d)

4,416 / 48.0

1,289 / 14.0

5,705 / 62.0

Natural Gas (MMcf / MMcf/d)

15,928 / 173.1

16,174 / 175.8

32,102 / 348.9

NGLs (MBbl / MBbl/d)

12 / –

2,076 / 22.6

2,088 / 22.7

Total (MBoe / MBoe/d)

7,083 / 77.0

6,060 / 65.9

13,143 / 142.9

Note: Totals may not calculate due to rounding.

  • 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 2022

Midland Basin

South Texas

Total

Oil (MBbl / MBbl/d)

19,105 / 52.3

4,874 / 13.4

23,979 / 65.7

Natural Gas (MMcf / MMcf/d)

63,459 / 173.9

62,471 / 171.2

125,930 / 345.0

NGLs (MBbl / MBbl/d)

31 / –

7,961 / 21.8

7,992 / 21.9

Total (MBoe / MBoe/d)

29,712 / 81.4

23,247 / 63.7

52,959 / 145.1

Note: Totals may not calculate due to rounding.

  • 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.

REALIZED PRICES BY OPERATING AREA

Fourth Quarter 2022

Midland Basin

South Texas

Total

(Pre/Post-hedge)(1)

Oil ($/Bbl)

$83.09

$79.82

$82.35 / $67.30

Natural Gas ($/Mcf)

$4.34

$4.69

$4.52 / $3.60

NGLs ($/Bbl)

nm

$26.06

$26.10 / $25.83

Per Boe

$61.62

$38.42

$50.92 / $42.12

Note: Totals may not calculate due to rounding.

 

Full Year 2022

Midland Basin

South Texas

Total

(Pre/Post-hedge)(1)

Oil ($/Bbl)

$95.08

$93.04

$94.67 / $73.21

Natural Gas ($/Mcf)

$6.82

$5.73

$6.28 / $4.92

NGLs ($/Bbl)

nm

$35.67

$35.66 / $32.60

Per Boe

$75.74

$47.12

$63.18 / $49.76

Note: Totals may not calculate due to rounding.

  • 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 DERIVATIVES

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.

2023  OPERATING PLAN AND GUIDANCE

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.
UPCOMING EVENTS

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.

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

CONFERENCE PARTICIPATION

  • February 27, 2023 – Credit Suisse 28th 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.
DISCLOSURES

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.

ABOUT THE COMPANY

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.

SM ENERGY INVESTOR CONTACTS

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

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Consolidated Balance Sheets

(in thousands, except share data)

December 31,

ASSETS

2022

2021

Current assets:

Cash and cash equivalents

$           444,998

$           332,716

Accounts receivable

233,297

247,201

Derivative assets

48,677

24,095

Prepaid expenses and other

10,231

9,175

Total current assets

737,203

613,187

Property and equipment (successful efforts method):

Proved oil and gas properties

10,258,368

9,397,407

Accumulated depletion, depreciation, and amortization

(6,188,147)

(5,634,961)

Unproved oil and gas properties, net of valuation allowance of $38,008 and $34,934,
respectively

487,192

629,098

Wells in progress

287,267

148,394

Other property and equipment, net of accumulated depreciation of $56,512 and $62,359,
respectively

38,099

36,060

Total property and equipment, net

4,882,779

4,575,998

Noncurrent assets:

Derivative assets

24,465

239

Other noncurrent assets

71,592

44,553

Total noncurrent assets

96,057

44,792

Total assets

$        5,716,039

$        5,233,977

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable and accrued expenses

$           532,289

$           563,306

Derivative liabilities

56,181

319,506

Other current liabilities

10,114

6,515

Total current liabilities

598,584

889,327

Noncurrent liabilities:

Revolving credit facility

Senior Notes, net

1,572,210

2,081,164

Asset retirement obligations

108,233

97,324

Deferred income taxes

280,811

9,769

Derivative liabilities

1,142

25,696

Other noncurrent liabilities

69,601

67,566

Total noncurrent liabilities

2,031,997

2,281,519

Stockholders’ equity:

Common stock, $0.01 par value – authorized: 200,000,000 shares; issued and outstanding:
121,931,676 and 121,862,248 shares, respectively

1,219

1,219

Additional paid-in capital

1,779,703

1,840,228

Retained earnings

1,308,558

234,533

Accumulated other comprehensive loss

(4,022)

(12,849)

Total stockholders’ equity

3,085,458

2,063,131

Total liabilities and stockholders’ equity

$        5,716,039

$        5,233,977

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Consolidated Statements of Operations

(in thousands, except per share data)

For the Three Months Ended
December 31,

For the Twelve Months Ended
December 31,

2022

2021

2022

2021

Operating revenues and other income:

Oil, gas, and NGL production revenue

$        669,250

$        852,368

$      3,345,906

$      2,597,915

Other operating income

2,068

2,592

12,741

24,979

Total operating revenues and other income

671,318

854,960

3,358,647

2,622,894

Operating expenses:

Oil, gas, and NGL production expense

150,667

143,285

620,912

505,416

Depletion, depreciation, amortization, and asset retirement
obligation liability accretion

143,611

200,011

603,780

774,386

Exploration (1)

10,826

12,550

54,943

39,296

Impairment

1,002

8,750

7,468

35,000

General and administrative (1)

32,843

37,062

114,558

111,945

Net derivative (gain) loss (2)

(11,168)

(22,524)

374,012

901,659

Other operating expense, net

879

1,415

3,493

46,069

Total operating expenses

328,660

380,549

1,779,166

2,413,771

Income from operations

342,658

474,411

1,579,481

209,123

Interest expense

(22,638)

(40,085)

(120,346)

(160,353)

Net loss on extinguishment of debt

(67,605)

(2,139)

Other non-operating income (expense), net

3,310

607

4,240

(464)

Income before income taxes

323,330

434,933

1,395,770

46,167

Income tax expense

(64,867)

(10,033)

(283,818)

(9,938)

Net income

$        258,463

$        424,900

$      1,111,952

$            36,229

Basic weighted-average common shares outstanding

122,485

121,535

122,351

119,043

Diluted weighted-average common shares outstanding

123,399

124,019

124,084

123,690

Basic net income per common share

$               2.11

$               3.50

$                9.09

$                0.30

Diluted net income per common share

$               2.09

$               3.43

$                8.96

$                0.29

Dividends per common share

$               0.15

$                   —

$                0.31

$                0.02

(1)  Non-cash stock-based compensation included in:

Exploration expense

$             1,000

$                946

$              3,965

$              3,950

General and administrative expense

3,914

3,682

14,807

14,869

Total non-cash stock-based compensation

$             4,914

$             4,628

$            18,772

$            18,819

(2)  The net derivative (gain) loss line item consists of the following:

Derivative settlement loss

$        115,620

$        268,696

$         710,700

$         748,958

(Gain) loss on fair value changes

(126,788)

(291,220)

(336,688)

152,701

Total net derivative (gain) loss

$         (11,168)

$         (22,524)

$         374,012

$         901,659

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS (UNAUDITED)

December 31, 2022

Consolidated Statements of Stockholders’ Equity

(in thousands, except share data and dividends per share)

Additional
Paid-in
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Loss

Total
Stockholders’
Equity

Common Stock

Shares

Amount

 Balances, December 31, 2020

114,742,304

$           1,147

$   1,827,914

$       200,697

$             (13,598)

$      2,016,160

Net income

36,229

36,229

Other comprehensive income

749

749

Cash dividends declared, $0.02 per share

(2,393)

(2,393)

Issuance of common stock under
Employee Stock Purchase Plan

313,773

3

2,636

2,639

Issuance of common stock upon vesting
of RSUs and settlement of PSUs, net of
shares used for tax withholdings

827,572

9

(9,081)

(9,072)

Stock-based compensation expense

60,510

1

18,818

18,819

Issuance of common stock through
cashless exercise of Warrants

5,918,089

59

(59)

 Balances, December 31, 2021

121,862,248

$           1,219

$   1,840,228

$       234,533

$             (12,849)

$      2,063,131

Net income

1,111,952

1,111,952

Other comprehensive income

8,827

8,827

Cash dividends declared, $0.31 per share

(37,927)

(37,927)

Issuance of common stock under
Employee Stock Purchase Plan

113,785

1

3,038

3,039

Issuance of common stock upon vesting
of RSUs and settlement of PSUs, net of
shares used for tax withholdings

1,291,427

13

(25,142)

(25,129)

Stock-based compensation expense

29,471

18,772

18,772

Purchase of shares under Stock
Repurchase Program

(1,365,255)

(14)

(57,193)

(57,207)

Balances, December 31, 2022

121,931,676

$           1,219

$   1,779,703

$   1,308,558

$               (4,022)

$      3,085,458

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Consolidated Statements of Cash Flows

(in thousands)

For the Three Months Ended
December 31,

For the Twelve Months Ended
December 31,

2022

2021

2022

2021

Cash flows from operating activities:

Net income

$         258,463

$         424,900

$      1,111,952

$           36,229

Adjustments to reconcile net income to net cash provided by
operating activities:

Depletion, depreciation, amortization, and asset retirement
obligation liability accretion

143,611

200,011

603,780

774,386

Impairment

1,002

8,750

7,468

35,000

Stock-based compensation expense

4,914

4,628

18,772

18,819

Net derivative (gain) loss

(11,168)

(22,524)

374,012

901,659

Derivative settlement loss

(115,620)

(268,696)

(710,700)

(748,958)

Amortization of debt discount and deferred financing costs

1,371

3,925

10,281

17,275

Net loss on extinguishment of debt

67,605

2,139

Deferred income taxes

66,061

9,847

269,057

9,565

Other, net

(1,426)

3,548

6,242

(3,753)

Changes in working capital:

Accounts receivable

37,235

8,776

38,554

(101,047)

Prepaid expenses and other

9,408

729

(1,055)

220

Accounts payable and accrued expenses

(105,476)

55,736

(109,562)

218,238

Net cash provided by operating activities

288,375

429,630

1,686,406

1,159,772

Cash flows from investing activities:

Capital expenditures

(288,088)

(124,576)

(879,934)

(674,841)

Other, net

267

2,092

(329)

7,606

Net cash used in investing activities

(287,821)

(122,484)

(880,263)

(667,235)

Cash flows from financing activities:

Proceeds from revolving credit facility

183,000

1,832,500

Repayment of revolving credit facility

(183,000)

(1,925,500)

Net proceeds from Senior Notes

392,771

Cash paid to repurchase Senior Notes

(584,946)

(450,776)

Repurchase of common stock

(36,966)

(57,207)

Net proceeds from sale of common stock

1,394

1,324

3,039

2,639

Dividends paid

(18,419)

(1,215)

(19,637)

(2,393)

Net share settlement from issuance of stock awards

(4,339)

(25,129)

(9,072)

Other, net

(9,981)

Net cash used in financing activities

(53,991)

(4,230)

(693,861)

(159,831)

Net change in cash, cash equivalents, and restricted cash

(53,437)

302,916

112,282

332,706

Cash, cash equivalents, and restricted cash at beginning of period

498,435

29,800

332,716

10

Cash, cash equivalents, and restricted cash at end of period

$         444,998

$         332,716

$         444,998

$         332,716

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Consolidated Statements of Cash Flows (Continued)

(in thousands)

For the Three Months Ended
December 31,

For the Twelve Months Ended
December 31,

2022

2021

2022

2021

Supplemental schedule of additional cash flow information:

Operating activities:

Cash paid for interest, net of capitalized interest

$            (8,572)

$          (10,378)

$        (134,240)

$        (136,606)

Net cash paid for incomes taxes

$                 (70)

$                 (62)

$          (10,576)

$               (864)

Investing activities:

Increase (decrease) in capital expenditure accruals and other

$          (20,801)

$          (19,711)

$           29,789

$          (10,826)

DEFINITIONS OF NON-GAAP MEASURES AND METRICS AS CALCULATED BY THE COMPANY

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.

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Production Data

For the Three Months Ended
December 31,

For the Twelve Months Ended
December 31,

2022

2021

Percent
Change

2022

2021

Percent
Change

Realized sales price (before the effect of derivative settlements):

Oil (per Bbl)

$     82.35

$     76.08

8 %

$     94.67

$     67.72

40 %

Gas (per Mcf)

$       4.52

$       6.35

(29) %

$       6.28

$       4.85

29 %

NGLs (per Bbl)

$     26.10

$     39.63

(34) %

$     35.66

$     33.67

6 %

Equivalent (per Boe)

$     50.92

$     58.54

(13) %

$     63.18

$     50.58

25 %

Realized sales price (including the effect of derivative settlements):

Oil (per Bbl)

$     67.30

$     53.11

27 %

$     73.21

$     48.99

49 %

Gas (per Mcf)

$       3.60

$       4.31

(16) %

$       4.92

$       3.44

43 %

NGLs (per Bbl)

$     25.83

$     22.99

12 %

$     32.60

$     20.00

63 %

Equivalent (per Boe)

$     42.12

$     40.09

5 %

$     49.76

$     36.00

38 %

Net production volumes: (1)

Oil (MMBbl)

5.7

7.8

(27) %

24.0

27.9

(14) %

Gas (Bcf)

32.1

31.3

3 %

125.9

108.4

16 %

NGLs (MMBbl)

2.1

1.6

32 %

8.0

5.4

49 %

Equivalent (MMBoe)

13.1

14.6

(10) %

53.0

51.4

3 %

Average net daily production: (1)

Oil (MBbls per day)

62.0

84.5

(27) %

65.7

76.5

(14) %

Gas (MMcf per day)

348.9

339.7

3 %

345.0

296.9

16 %

NGLs (MBbls per day)

22.7

17.2

32 %

21.9

14.7

49 %

Equivalent (MBoe per day)

142.9

158.3

(10) %

145.1

140.7

3 %

Per Boe data: (1)

Lease operating expense

$       5.20

$       4.21

24 %

$       5.03

$       4.39

15 %

Transportation costs

$       2.86

$       2.61

10 %

$       2.83

$       2.71

4 %

Production taxes

$       2.43

$       2.80

(13) %

$       3.07

$       2.36

30 %

Ad valorem tax expense

$       0.97

$       0.22

341 %

$       0.79

$       0.38

108 %

General and administrative (2)

$       2.50

$       2.55

(2) %

$       2.16

$       2.18

(1) %

Derivative settlement loss

$     (8.80)

$   (18.45)

52 %

$   (13.42)

$   (14.58)

8 %

Depletion, depreciation, amortization, and asset
retirement obligation liability accretion

$     10.93

$     13.74

(20) %

$     11.40

$     15.08

(24) %

(1) Amounts and percentage changes may not calculate due to rounding.

(2) Includes non-cash stock-based compensation expense per Boe of $0.30 and $0.25 for the three months ended December 31, 2022, and 2021, respectively, and $0.28 and $0.29 for the twelve months ended December 31, 2022, and 2021, respectively.

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Adjusted EBITDAX Reconciliation  (1)

(in thousands)

Reconciliation of net income (GAAP) and net cash provided by
operating activities (GAAP) to Adjusted EBITDAX (non-GAAP):

For the Three Months Ended
December 31,

For the Twelve Months Ended
December 31,

2022

2021

2022

2021

Net income (GAAP)

$         258,463

$         424,900

$     1,111,952

$           36,229

Interest expense

22,638

40,085

120,346

160,353

Income tax expense

64,867

10,033

283,818

9,938

Depletion, depreciation, amortization, and asset retirement
obligation liability accretion

143,611

200,011

603,780

774,386

Exploration (2)

9,826

11,604

50,978

35,346

Impairment

1,002

8,750

7,468

35,000

Stock-based compensation expense

4,914

4,628

18,772

18,819

Net derivative (gain) loss

(11,168)

(22,524)

374,012

901,659

Derivative settlement loss

(115,620)

(268,696)

(710,700)

(748,958)

Net loss on extinguishment of debt

67,605

2,139

Other, net

(4,679)

(1,900)

(9,743)

507

Adjusted EBITDAX (non-GAAP)

$         373,854

$         406,891

$     1,918,288

$     1,225,418

Interest expense

(22,638)

(40,085)

(120,346)

(160,353)

Income tax expense

(64,867)

(10,033)

(283,818)

(9,938)

Exploration (2)(3)

(8,851)

(11,604)

(36,810)

(35,346)

Amortization of debt discount and deferred financing costs

1,371

3,925

10,281

17,275

Deferred income taxes

66,061

9,847

269,057

9,565

Other, net

2,278

5,448

1,817

(4,260)

Net change in working capital

(58,833)

65,241

(72,063)

117,411

Net cash provided by operating activities (GAAP)

$         288,375

$         429,630

$     1,686,406

$     1,159,772

(1)

See “Definitions of non-GAAP Measures and Metrics as Calculated by the Company” above.

(2)

Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying consolidated statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(3)

For the twelve months ended December 31, 2022, amount is net of certain capital expenditures related to unsuccessful exploration efforts outside of our core areas of operations.

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Adjusted Net Income Reconciliation (1)

(in thousands, except per share data)

Reconciliation of net income (GAAP) to adjusted net income (non-GAAP):

For the Three Months
Ended December 31,

For the Twelve Months
Ended December 31,

2022

2021

2022

2021

Net income (GAAP)

$       258,463

$       424,900

$    1,111,952

$          36,229

Net derivative (gain) loss

(11,168)

(22,524)

374,012

901,659

Derivative settlement loss

(115,620)

(268,696)

(710,700)

(748,958)

Impairment

1,002

8,750

7,468

35,000

Net loss on extinguishment of debt

67,605

2,139

Other, net

(985)

(885)

(3,969)

2,223

Tax effect of adjustments (2)

27,509

61,488

57,632

(41,678)

Valuation allowance on deferred tax assets

(61,488)

41,678

Adjusted net income (non-GAAP)

$       159,201

$       141,545

$       904,000

$       228,292

Diluted net income per common share (GAAP)

$              2.09

$              3.43

$              8.96

$              0.29

Net derivative (gain) loss

(0.09)

(0.18)

3.01

7.29

Derivative settlement loss

(0.94)

(2.17)

(5.73)

(6.06)

Impairment

0.01

0.07

0.06

0.28

Net loss on extinguishment of debt

0.54

0.02

Other, net

(0.01)

(0.01)

(0.03)

0.03

Tax effect of adjustments (2)

0.22

0.50

0.46

(0.34)

Valuation allowance on deferred tax assets

(0.50)

0.34

Adjusted net income per diluted common share (non-GAAP)

$              1.29

$              1.14

$              7.29

$              1.85

Basic weighted-average common shares outstanding

122,485

121,535

122,351

119,043

Diluted weighted-average common shares outstanding

123,399

124,019

124,084

123,690

Note: Amounts may not calculate due to rounding.

(1)

See “Definitions of non-GAAP Measures and Metrics as Calculated by the Company” above.

(2)

The tax effect of adjustments for each of the three and twelve months ended December 31, 2022, and 2021, was calculated using a tax rate of 21.7%. This rate approximates the Company’s statutory tax rate for the respective periods, as adjusted for ordinary permanent differences.

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Regional proved oil and gas reserve quantities

Midland Basin

South Texas

Total

Year-end 2022 estimated proved reserves

Oil (MMBbl)

153.1

52.7

205.8

Gas (Bcf)

625.1

777.8

1,402.9

NGL (MMBbl)

0.2

97.6

97.8

MMBoe

257.4

280.0

537.4

% Proved developed

64 %

55 %

59 %

Note: Amounts may not calculate due to rounding.

 

Pre-tax PV-10 Reconciliation  (1)

(in millions)

As of December 31,

Reconciliation of standardized measure of discounted future net cash flows (GAAP) to Pre-tax PV-10 (non-GAAP):

2022

2021

Standardized measure of discounted future net cash flows (GAAP)

$                          9,962.1

$                          6,962.6

Add: 10 percent annual discount, net of income taxes

7,551.5

4,844.9

Add: future undiscounted income taxes

3,888.3

2,130.3

Pre-tax undiscounted future net cash flows

21,401.9

13,937.8

Less: 10 percent annual discount without tax effect

(9,247.4)

(5,779.2)

Pre-tax PV-10 (non-GAAP)

$                        12,154.5

$                          8,158.6

(1) See “Definitions of non-GAAP Measures and Metrics as Calculated by the Company” above.

 

Reconciliation of Total Principal Amount of Debt to Net Debt  (1)

(in thousands)

As of December 31,

2022

2021

Principal amount of Senior Secured Notes (2)

$                                   —

$                         446,675

Principal amount of Senior Unsecured Notes (2)

1,585,144

1,689,913

Revolving credit facility (2)

Total principal amount of debt (GAAP)

1,585,144

2,136,588

Less: Cash and cash equivalents

444,998

332,716

Net Debt (non-GAAP)

$                     1,140,146

$                     1,803,872

(1) See “Definitions of non-GAAP Measures and Metrics as Calculated by the Company” above.

(2) Amounts are from Note 5 – Long-term Debt in Part II, Item 8 of the Company’s Form 10-K for the years ended December 31, 2022, and 2021, respectively.

 

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS

December 31, 2022

Adjusted Free Cash Flow (1)

(in thousands)

For the Three Months Ended
December 31,

For the Twelve Months Ended
December 31,

2022

2021

2022

2021

Net cash provided by operating activities (GAAP)

$       288,375

$       429,630

$    1,686,406

$    1,159,772

Net change in working capital

58,833

(65,241)

72,063

(117,411)

Cash flow from operations before net change in working capital (non-GAAP)

347,208

364,389

1,758,469

1,042,361

Capital expenditures (GAAP)

288,088

124,576

879,934

674,841

Increase (decrease) in capital expenditure accruals and other

(20,801)

(19,711)

29,789

(10,826)

Capital expenditures before accruals and other (non-GAAP)

267,287

104,865

909,723

664,015

Adjusted free cash flow (non-GAAP)

$         79,921

$       259,524

$       848,746

$       378,346

(1) See “Definitions of non-GAAP Measures and Metrics as Calculated by the Company” above.

 

SOURCE SM Energy Company


Legal Notice