石油和天然气 360

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 2023 年第四季度销量创历史新高，接近指导值上限 ~

~ 除了支付创始人收购的最终款项外，进一步减少债务 ~

德克萨斯州伍德兰兹，2024 年 1 月 29 日（环球通讯社）——Ring Energy, Inc.（纽约证券交易所美国股票代码：REI）（“Linging”或“公司”）今天提供了该公司的运营和财务最新信息2023 年第四季度的生产和资本支出指导以及 2024 年第一季度的生产和资本支出指导。

主要 亮点

• 2023 年第四季度销量约为每天 19,400 桶油当量 (“oe/d”)（70% 石油），接近公司指导的上限，即 18,900 至 19,500 桶油当量/天；
• 对第四季度销售产生积极影响的是最近完成的 Founders Oil & Gas IV, LLC（“ounders”和“ounders Acquisition”）资产收购，该资产于 2023 年 8 月 15 日完成，整整三个月的生产量如下：以及公司于 11 月底结束的 2023 年发展计划的成功；
• 2023 年第四季度进一步减少债务 300 万美元，同时还为 12 月创始人收购的 1190 万美元最终付款提供资金；
  • 截至 2023 年底，公司信贷额度借款额为 4.25 亿美元；
• 指导 2024 年第一季度平均销量为 18,000 至 18,500 桶油当量/天（约 69% 石油）；
  • 影响公司迄今为止销量的是约 1,900 桶油当量/天的产量推迟 10 天，这与最近严寒的冬季天气有关。此后生产已恢复；
  • Ring于11月下旬完成了2023年钻井计划，并于1月初启动了2024年计划，第一口井预计将于2月上线；和
• 预计第一季度资本支出为 3,700 万至 4,200 万美元，主要与分阶段的两台钻机钻井计划（一台水平钻机和一台垂直钻机）相关；
  • 计划钻四到五口水平井和四到六口直井。

董事会主席兼首席执行官保罗·D·麦金尼 (Paul D. McKinney) 先生评论道：“2023 年第四季度的销售额创历史新高，接近指导上限，但更重要的是超出了我们对原油预期的上限销售量。第四季度的业绩非常出色，我们期待在三月初报告我们的完整业绩。我们在此期间取得的成功得益于我们最近收购创始人的整个季度的生产影响，以及我们于 11 月底结束的 2023 年钻探计划的持续成功。此外，我们还清偿了 300 万美元的债务，同时为创始人收购支付了 1190 万美元的最终延期付款。减少债务仍然是公司的首要任务，我们在 2022 年和 2023 年进行的目标收购使我们能够以比单独运作快得多的速度偿还债务。”

麦金尼先生总结道：“进入 2024 年，我们打算保留根据石油和天然气价格变化调整资本支出水平的灵活性。” 从 2024 年开始，我们实施了分阶段的两台钻机钻井计划，目标是实现最高回报率的水平和垂直钻井库存。这种方法为我们提供了应对不断变化的市场条件所需的灵活性。与过去一样，我们的工作重点是增强公司的财务状况，进一步减少债务是首要任务。我们感谢股东的支持，并期待 2024 年取得成功。”

关于环能源公司

Ring Energy, Inc. 是一家石油和天然气勘探、开发和生产公司，目前的业务重点是开发其二叠纪盆地资产。欲了解更多信息，请访问 www.ringenergy.com。

安全港声明

本新闻稿包含经修订的 1933 年证券法第 27A 条和经修订的 1934 年证券交易法第 21E 条含义内的前瞻性陈述。前瞻性陈述涉及多种风险和不确定性，包括但不限于有关公司战略和前景的陈述。前瞻性陈述包括有关公司预期未来储量、产量、财务状况、业务战略、收入、收益、成本、资本支出和债务水平以及未来运营管理计划和目标的陈述。前瞻性陈述基于 Ring 及其管理层根据其经验和对历史趋势、当前状况和预期未来发展的看法以及当前情况下适当的其他因素所做的当前预期、假设和分析。然而，实际结果和发展是否符合预期，受到许多重大风险和不确定因素的影响，包括但不限于：石油、液化天然气或天然气价格的下跌；勘探、开发和生产活动的成功程度；可能对开发或生产活动产生负面影响的恶劣天气条件；勘探和开发支出的时间安排；储量估计或其背后的假设不准确；由于商品价格变化而对储量估算进行修订；减值减值对财务报表的影响；与债务水平以及定期重新确定公司信贷安排下的借款基础和利率相关的风险；Ring 有能力从运营中产生足够的现金流，以满足其资本支出预算的内部资助部分；对冲对经营业绩的影响；以及Ring 替代石油和天然气储量的能力。此类声明受到公司向美国证券交易委员会提交的报告（包括截至 2022 年 12 月 31 日的财年的 10-K 表格）以及其他文件中披露的某些风险和不确定性的影响。除法律要求外，Ring 不承担公开修改或更新任何前瞻性陈述的义务。

联系信息

Al Petrie 顾问
Al Petrie，高级合伙人
电话：281-975-2146
电子邮件：  apetrie@ringenergy.com

资料来源：Ring Energy, Inc.

发布日期：2024 年 1 月 29 日

石油和天然气 360

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纳斯达克

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休斯顿——周五，埃克森美孚公司公布第三季度利润为 91 亿美元，较去年同期创纪录的盈利下降约 54%，但随着油价回升，较上一季度有所上升。美国最大石油生产商的盈利受益于原油价格较上一季度上涨以及汽油和柴油的需求。

 

 在该公司指出化工利润和炼油利润疲软后，华尔街本月 下调了第三季度前景。

埃克森美孚的强劲业绩导致了两笔全股票交易：页岩竞争对手先锋自然资源公司和碳管道运营商登伯里公司，这两笔交易均因股价接近历史最高纪录而达成。

第三季度利润为每股 2.25 美元，而去年同期为 4.68 美元，当时俄罗斯入侵乌克兰后石油和天然气价格攀升。

伦敦证交所的数据显示，最新一季度的业绩受益于全球油价，该季度平均油价为每桶 85.92 美元，高于第二季度的每桶 77.73 美元。

这一业绩得益于石油和燃料价格上涨，但受到原材料成本上涨打击的埃克森化学业务的影响。化学产品公司第三季度盈利为 2.49 亿美元，低于第二季度的 8.28 亿美元。

其现金储备继续增加，较第二季度增长 10%，达到 330 亿美元。

“我们对我们的现金余额感觉非常好，”首席财务官凯瑟琳·米克尔斯在接受采访时表示。“这使我们处于有利位置，最终确保当大宗商品周期最终对我们不利时，我们拥有所需的灵活性。”

Mikells 表示，该公司将维持 2023 年 370 万桶/日的产量目标不变。今年还计划进行 175 亿美元的回购。

埃克森美孚第三季度实现了到年底比 2019 年减少成本 90 亿美元的目标。

埃克森美孚在一个季度前完成了与 2019 年相比 90 亿美元的年终成本节约目标。这家石油生产商还将其全年资本支出置于其 230 亿至 250 亿美元指导的上限。

该公司一直在世界各地出售资产，专注于美国页岩油和南美洲圭亚那更有利可图的项目，最近还出售了其意大利炼油厂。

 

投资

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休斯顿——雪佛龙（纽约证券交易所代码：CVX）公布的第三季度利润大幅低于华尔街预期，导致其股价在盘前交易中下跌。由于原油价格下跌以及成本上涨抑制了炼油和化工利润，石油公司的盈利已从去年同期的创纪录水平大幅下滑。按照历史标准衡量，结果仍然强劲，但远低于去年同期的水平。

该公司盈利 65 亿美元，低于去年同期的 112 亿美元。根据 LSEG 数据，调整后利润为每股 3.05 美元，而分析师预期为每股 3.75 美元。

雪佛龙在第二季度警告称，维护其石油和天然气生产以及炼油业务将损害业绩，导致盈利低于预期。该公司在哈萨克斯坦的一个项目也遭受了挫折，其 Tengizchevroil 项目的石油和天然气产量扩大推迟了约六个月。

早盘交易中股价下跌 5.4% 至 146.40 美元。

埃克森美孚 (NYSE: XOM ) 和 TotalEnergies (EPA: TTEF ) 也因原油和炼油利润疲软而公布了第三季度业绩下滑  ，埃克森美孚的利润下降了 54%，TotalEnergies 的利润下降了 35%。

雪佛龙同意以 530 亿美元的全股票交易收购美国竞争对手赫斯公司（纽约证券交易所股票代码：HES ），以扩大其页岩和深水石油产量和储量。

除Hess外，它还收购了美国页岩油气生产商PDC Energy（纳斯达克股票代码：PDCE）以及美国储氢公司ACES Delta的多数股权。

加拿大皇家银行分析师 Biraj Borkhataria 写道：“对于 CVX 股东来说，这将是艰难的一天。”他将盈利下降描述为“令人失望”，但将其归咎于非经常性项目。

本季度资本支出增长超过 50%，达到 47 亿美元，部分原因是收购了 ACES Delta。Tengizchevroil 扩建项目的总成本预计将增加 10 亿美元。

本季度石油和天然气开采利润从去年同期的 93 亿美元下降约 38% 至 57.6 亿美元。

总体而言，PDC Energy 交易的石油和天然气产量增长了 4%，达到每天 315 万桶 (boed)，使利润较低的天然气产量增加了  25%。雪佛龙一年前生产了 303 万桶油当量。

由于供应紧张推高了原油价格，油价最近从年中的低迷中反弹。该公司的运营现金流从一年前的 153 亿美元降至 97 亿美元。

其炼油业务营业利润为 16.8 亿美元，低于一年前的 25.3 亿美元，原因是美国以外地区的业绩大幅下滑。美国炼油业务的收益被海外疲软所抵消，利润和投入下降。

石油和天然气 360

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德克萨斯州休斯顿 / ACCESSWIRE / 2023 年 5 月 15 日 /  PEDEVCO Corp. （纽约证券交易所股票代码：PED）（“EDEVCO”或“公司”）是一家从事战略性高增长能源收购和开发的能源公司美国项目今天公布了截至 2023 年 3 月 31 日的三个月财务业绩，并提供了运营更新。

主要亮点包括：

• 截至 2023 年 3 月 31 日的三个月（“净 1 2023”）平均每天生产约 1,428 桶石油当量（“OEPD”）（80.4% 石油），2023 年第一季度收入增加 820 万美元截至 2022 年 3 月 31 日的三个月内赚取的收入的 15% (“净1 2022”)。
• 报告的运营收入为 160 万美元，运营费用（包括一般和管理费用、折旧、消耗和摊销费用以及租赁运营费用）为 650 万美元，较 2022 年第一季度分别增长 30% 和 12%。
• 报告净利润为 180 万美元，即每股基本和稀释已发行股票 0.02 美元，而 2022 年第一季度净利润为 130 万美元，即每股基本和稀释已发行股票 0.02 美元。
• 调整后 EBITDA（一项非 GAAP 财务指标（下文将详细讨论））增长了 28%，达到 490 万美元，而 2022 年第一季度为 380 万美元。
• 截至 2023 年 3 月 31 日，报告的现金和现金等价物（包括 355 万美元的限制性现金）为 1,770 万美元，债务为零。
• 2023 年第一季度产量增长归因于 DJ 盆地 14 口新的未运营井开始生产，其中包括 Barracuda 项目的 6 口井（公司持有该项目约 35.8% 的工作权益，并于 2022 年 12 月开始生产）和 8 口井公司持有罗斯单位约 4.7% 的工作权益，该权益已于 2023 年 2 月上旬上交 (TIL)，并应在 2023 年第二季度继续增加产量。
• 目前预计将于 2023 年下半年参与 DJ 盆地另外 7 个未运营的 Niobrara 水平井，公司持有该盆地约 18% 的作业权益。许可证已到位；然而，该公司尚未被运营合作伙伴 AFE 收购。
• 目前允许并确保供应商承诺在 DJ 盆地钻探和完成 4 口已运营的 Niobrara 水平井，该公司拥有该盆地约 70% 的工作权益，钻探预计将于 2023 年底至 2024 年初开始。

公司总裁 J. Douglas Schick 表示：“我们对 2022 年非运营开发计划的结果感到满意，该计划已于 2023 年第一季度开始看到。该计划帮助我们实现了强劲的运营和财务业绩。尽管 2023 年第一季度的油价低于 2022 年第一季度，但仍保持零债务并控制一般管理费用，但该季度的股东表现仍有所提高，包括产量、现金流、每股收益和调整后 EBITDA 的增长。我们预计到 2023 年第二季度，产量将继续出现有意义的增长，因为我们在 2022 年参与的 14 口非作业井的产量现已全部上线。我们寻求继续利用我们强大的现金状况和零债务来继续增加我们的产量、收入和利润，并增加我们的资产基础，以造福我们的股东。”

财务摘要：

截至 2023 年 3 月 31 日的三个月，我们报告的净利润为 180 万美元，即每股基本和稀释流通股 0.02 美元，而 2022 年第一季度的净利润为 130 万美元，即每股基本和稀释流通股 0.02 美元。

与上年同期相比，本期净利润增加 50 万美元，主要是由于净收入和利息收入合计增加 120 万美元，被总运营费用增加 70 万美元所抵消（在更多详情见下文）。

我们报告 2023 年第一季度的运营费用为 650 万美元，而 2022 年第一季度为 580 万美元。增加 70 万美元主要是由于 2023 年年初的计划活动导致租赁运营费用增加 10 万美元运营和设施改进以及设备维护的时间安排，以及由于本期产量增加而导致的折旧、消耗、摊销和增值费用增加 70 万美元，与上年同期相比，本期一般和行政费用减少 10 万美元前期。

调整后 EBITDA（一项非 GAAP 财务指标（下文将详细讨论））在 2023 年第一季度增长了 28%，达到 490 万美元，而 2022 年第一季度为 380 万美元。

截至 2023 年 3 月 31 日，现金和现金等价物为 1,770 万美元（包括 355 万美元限制性现金），而截至 2022 年 12 月 31 日为 3,300 万美元（包括 355 万美元限制性现金），减少的主要原因是资本支出增加与我们的钻井和完井活动相关。

产量、价格和收入：

2023 年第一季度产量为 128,514 桶油当量（“OE”），其中包括 103,329 桶石油、876.58 亿立方英尺（“CF”）天然气和 10,575 桶油当量（“CF”）天然气液体（“E”）。 GLs”）。液体产量占本季度总产量的 88.6%。

2023 年第一季度，我们的平均实现原油销售价格为每桶 72.19 美元，平均实现天然气价格为每桶 5.75 美元，平均实现 NGL 销售价格为每桶 18.90 美元。我们本季度的综合平均实现销售价格为每桶油当量 63.52 美元，与 2022 年第一季度的每桶油当量 73.36 美元相比下降了 13%。

2023 年第一季度的原油、天然气和液化天然气总收入增加了 110 万美元，即 15%，达到 820 万美元，而去年同期为 710 万美元，这是由于 200 万美元的有利数量差异被不利的价格所抵消差异为 90 万美元。产量的增加与我们参与DJ盆地资产的14口非作业井的积极业绩有关（其中六口于2022年底开始生产，其中八口于截至2023年3月31日的三个月内开始生产） ，加上我们现有运营的二叠纪盆地和 DJ 盆地资产的产量下降保持相对平稳。

租赁运营费用（“OE”）：

2023 年第一季度的总 LOE 为 250 万美元，而 2022 年第一季度的总 LOE 为 240 万美元。增加 10 万美元主要是由于 2023 年初计划开展活动，以提前推进运营和设施改进以及设备维护的时间。

折旧、消耗、摊销和增值（“EDD&A”）：

DD&A 从 2022 年第一季度的 190 万美元增加到 2023 年第一季度的 260 万美元。增加 70 万美元主要是由于本期产量（如上所述）较上一期增加。

一般及行政费用（“&A”）：

与 2022 年第一季度相比，2023 年第一季度的一般管理费用（不包括股权激励）名义上有所减少，因为公司继续努力控制成本并保持在不同时期的预算范围内。

由于某些员工自愿离职而丧失了某些员工股票期权和未归属限制性股票，因此包含在运营报表中的一般和管理费用中的股份薪酬名义上有所减少。采用股份补偿的目的是节省现金资源用于油田开发活动和运营。

利息收入和其他费用：

我们从计息现金账户中赚取了 98,000 美元的利息，与上一期相比，本期利率有所上升。2023 年第一季度的其他收入为 35,000 美元，主要与上一期间供应商纠纷解决所抵消的旧管销售有关。

营运资金和流动资金：

截至2023年3月31日，我们的流动资产总额为2010万美元，超过了我们的流动负债总额680万美元，导致营运资金盈余为1330万美元，而截至2022年12月31日，我们的流动资产总额为3210万美元，超过了我们的流动负债总额。负债 1,700 万美元，营运资本盈余为 1,510 万美元。我们的营运资本盈余减少了 180 万美元，主要与用于资助我们当前资本钻探预算的现金有关。

运营更新：

我们目前正在申请许可证并确保供应商承诺在 DJ 盆地钻探和完成 4 口已运营的 Niobrara 水平井，我们在该盆地拥有约 70% 的工作权益，预计钻探将于 2023 年底至 2024 年初开始。根据与 DJ 盆地非作业合作伙伴的讨论，我们目前计划于 2023 年下半年参与 DJ 盆地另外 7 口非作业 Niobrara 水平井，我们持有约 18% 的工作权益。该项目的许可证已到位；然而，我们尚未获得运营合作伙伴的 AFE 认可。根据与 2023 年计划的这些 DJ 盆地资产项目的时间安排相关的资金到位情况，我们还可能寻求在 2023 年在我们的二叠纪盆地资产上钻探并完成另外 3 个圣安德烈斯水平井。我们拥有这些圣安德烈斯井的许可证，如果我们的 DJ Basin Asset 运营或非运营项目推迟到 2024 年初之后，我们计划钻探并完成该项目。

有关我们截至 2023 年 3 月 31 日的三个月经营业绩的更多信息，包括我们完整的财务报表和脚注，请参阅今天早些时候向美国证券交易委员会提交的 10-Q 表格季度报告。网址：  www.sec.gov。

关于 PEDEVCO 公司

PEDEVCO Corp.（纽约证券交易所美国股票代码：PED）是一家上市能源公司，在美国从事战略性高增长能源项目的收购和开发。该公司的主要资产是位于新墨西哥州东部二叠纪盆地西北陆架的二叠纪盆地资产，以及位于科罗拉多州韦尔德县和摩根县以及怀俄明州南部的DJ盆地资产。PEDEVCO 总部位于德克萨斯州休斯顿。

非公认会计准则财务信息的使用

本财报讨论了 EBITDA 和调整后 EBITDA，它们是作为公司业绩的补充指标而提出的。这些衡量标准不符合公认会计原则 (GAAP)，因此不应被视为 GAAP 绩效衡量标准的替代方案。EBITDA 代表未计利息、税项、折旧和摊销前的净利润。调整后 EBITDA 定义为 EBITDA 减去基于股份的薪酬。列出 EBITDA 和调整后 EBITDA 是因为我们相信，由于该期间的各种非现金项目，它们为投资者提供了额外的有用信息。EBITDA 和调整后 EBITDA 也经常被分析师、投资者和其他相关方用来评估我们行业的公司。我们使用 EBITDA 和调整后 EBITDA 作为 GAAP 业绩衡量标准的补充，为投资者提供额外的财务分析框架，管理层除了历史经营业绩外，还使用该框架作为财务、运营和规划决策的基础，并提供第三方衡量的衡量标准表明有助于评估公司及其经营业绩。EBITDA 和调整后 EBITDA 作为分析工具存在局限性，您不应孤立地考虑它们，也不应将它们作为根据 GAAP 报告的运营业绩分析的替代品。其中一些限制包括： EBITDA 和调整后 EBITDA 不反映现金支出、未来资本支出要求或合同承诺；EBITDA 和调整后 EBITDA 不反映营运资金需求的变化或现金需求；EBITDA 和调整后 EBITDA 不反映债务或现金所得税支付的重大利息支出，或偿还利息或本金所需的现金需求。例如，虽然折旧和摊销是非现金费用，但正在折旧和摊销的资产将来往往必须更换，而 EBITDA 和调整后 EBITDA 并不反映此类更换的任何现金需求。此外，我们行业中的其他公司计算 EBITDA 和调整后 EBITDA 的方式可能与 PEDEVCO Corp. 不同，从而限制了其作为比较指标的有用性。您不应孤立地考虑 EBITDA 和调整后 EBITDA，也不应将其视为根据 GAAP 报告的公司业绩分析的替代品。公司对这些措施的介绍不应被解释为未来业绩将不受异常或非经常性项目影响的推断。我们通过将这些非 GAAP 衡量标准与最具可比性的 GAAP 衡量标准进行调节来弥补这些限制。我们鼓励投资者和其他人全面审查我们的业务、经营业绩和财务信息，而不是依赖任何单一的财务指标，并将这些非公认会计原则指标与最直接可比的公认会计原则财务指标结合起来查看。

关于前瞻性陈述的警告声明

本新闻稿可能包含前瞻性陈述，包括有关管理层对 PEDEVCO 未来预期、计划和前景的看法的信息，这些信息符合联邦证券法的含义，包括《私人证券诉讼改革法案》中的安全港条款。 1995 年（“法案”）。特别是，当在前面的讨论中使用时，词语“说”、“可以”、“期望”、“打算”、“计划”、“寻求”、“”预期、“相信”、“估计”、“预测”、“潜力”、“继续”、“可能”、“很好”、“应该” � 这些术语和类似表达的变体，或者这些术语或类似表达的否定形式旨在识别该法案和此类法律含义内的前瞻性陈述，并受到该法案和适用的安全港的约束法律。除历史事实外，本新闻稿中有关行动、事件或发展的任何陈述均为前瞻性陈述。这些陈述涉及已知和未知的风险、不确定性和其他因素，可能导致 PEDEVCO 及其子公司的结果与此类陈述中明示或暗示的结果存在重大差异。前瞻性陈述包括对公司战略、未来运营、开发计划和计划的预测和估计，包括其成本、钻井地点、预计石油、天然气和天然气液体产量、价格实现、预计运营、一般和行政及其他成本、预计资本支出、效率和成本削减计划成果、有关未来生产、成本和现金流、流动性和资本结构的报表。这些前瞻性陈述基于我们当前的预期、假设以及我们根据我们的经验和对历史趋势、当前状况和预期未来发展的看法以及我们认为在这种情况下适当的其他因素所做的分析。 。然而，实际结果和发展是否符合我们的预期和预测，会受到许多风险和不确定性的影响，包括石油和天然气价格的波动，我们在发现、估计、开发和替代石油和天然气储量方面的成功，我们的业务无法盈利或无法产生足够的现金流来履行我们的义务的风险；与石油、天然气和液化天然气未来价格相关的风险；与石油和天然气收集、运输和储存设施的状况和可用性相关的风险；与石油和天然气行业法律和监管环境变化相关的风险，新的或修订的环境立法和监管举措；与石油输出国组织和其他生产国可能实施的原油生产配额或其他行动有关的风险；技术进步；公司经营所在市场的经济、监管和政治环境不断变化；国内和国际经济、市场和政治总体状况，包括俄罗斯和乌克兰之间的军事冲突以及全球对此冲突的反应；竞争对手或监管机构的行为；由于战争、事故、政治事件、恶劣天气、网络威胁、恐怖行为或公司无法控制的其他自然或人为原因而导致公司运营的潜在中断或中断；与需要额外资本来完成未来收购、开展我们的业务以及以有利的条件为我们的业务提供资金（如果有的话）相关的风险，以及此类资金的可用性及其成本；与对我们不经营的财产活动的有限控制以及石油和天然气业务的投机性质相关的风险；与钻井、完井和强化采收率作业的不确定性相关的风险；与我们普通股的流动性不足和波动性相关的风险、对现任管理层的依赖、我们的首席执行官兼董事会成员西蒙·库克斯博士实益拥有我们大部分普通股的事实，以及我们维持我们的上市的能力纽约证券交易所美国证券交易所的普通股；流行病、政府对此的应对措施、经济衰退和由此引起的可能的衰退；通货膨胀风险和近期利率上升，以及由此或降低通货膨胀的努力引起的衰退和经济衰退的风险；与产油国军事冲突有关的风险；经济状况的变化；供应品、材料、承包商和服务的可用性和成本限制，可能会延迟油井的钻探或完井或使此类油井更加昂贵；未来开发成本的金额和时间；替代能源的可用性和需求；监管变化，包括与二氧化碳和温室气体排放相关的监管变化；以及 PEDEVCO 不时向美国证券交易委员会提交的文件中包含的其他内容，其中许多内容超出了我们的控制范围，包括但不限于“风险因素”和“有关的警示性说明”其已向美国证券交易委员会提交并不时提交的 10-K 表格、10-Q 表格以及 8-K 表格中的“前瞻性陈述”部分，包括但不包括仅限于截至 2022 年 12 月 31 日的年度 10-K 表格年度报告和截至 2023 年 3 月 31 日的季度 10-Q 表格季度报告。这些报告可在 www.sec.gov 上获取。该公司警告称，上述重要因素清单并不完整。公司或代表公司行事的任何人随后发表的所有书面和口头前瞻性陈述均明确符合上述警示性陈述。其他未知或不可预测的因素也可能对 PEDEVCO 的未来业绩产生重大不利影响和/或可能导致我们的实际业绩和财务状况与前瞻性陈述中所示的结果和财务状况存在重大差异。本新闻稿中包含的前瞻性陈述仅在本新闻稿发布之日作出。PEDEVCO 无法保证未来的结果、活动水平、表现或成就。因此，您不应过度依赖这些前瞻性陈述。我们没有义务公开更新任何这些前瞻性陈述以反映实际结果、新信息或未来事件、假设的变化或影响前瞻性陈述的其他因素的变化，除非适用法律要求。如果我们更新一项或多项前瞻性陈述，不应推断我们将针对这些或其他前瞻性陈述进行其他更新。我们 2023 年资本预算的内部预测、预期或信念可能会因多种因素而发生变化，包括但不限于石油和天然气的现行价格、企业和政府采取的行动、持续的结果、现行的经济状况情况、商品价格以及行业条件和法规。

PEDEVCO CORP.
合并资产负债表
（金额以千为单位，除股份和每股数据外）

		2023 年 3 月 31 日				12月31日，
		（未经审计）				2022年
资产
当前资产：
现金及现金等价物		$	14,139			$	29,430
应收账款——石油和天然气			5,788				2,430
预付费用和其他流动资产			149				249
流动资产总额			20,076				32,109
石油和天然气特性：
石油和天然气资产，须摊销，净值			82,692				79,372
石油和天然气资产，不需摊销，净值			1,500 人				第775章
石油和天然气总资产（净值）			84,192				80,147
经营租赁——使用权资产			45				71
其他资产			3,821				3,783
总资产		$	108,134			$	116,110
负债和股东权益
流动负债：
应付账款		$	3,683			$	1,556
预提费用			1,375				13,835
应付收入			1,000				1,018
经营租赁负债——流动			51				81
资产报废义务——当前			第658章				第472章
流动负债总额			6,767				16,962
长期负债：
资产报废义务，扣除流动部分			2,628				2,689
负债总额			9,395				19,651
承诺和或有事项
股东权益：
普通股，面值 0.001 美元，授权 200,000,000 股；已发行及流通股分别为 87,040,267 股和 85,790,267 股			87				86
资本的额外支付			223,631				223,114
累计赤字			（124,979	）			（126,741	）
股东权益合计			98,739				96,459
负债及股东权益合计		$	108,134			$	116,110

PEDEVCO CORP.
合并经营报表
（单位为千，除股份和每股数据外）

		截至 3 月 31 日的三个月，
		2023年				2022年
收入：
石油和天然气销售		$	8,164			$	7,090
营业费用：
租赁运营成本			2,466				2,356
销售、一般和管理费用			1,488				1,592 人
折旧、消耗、摊销和增值			2,581				1,886
总营业费用			6,535				5,834
营业收入			1,629				1,256
其他的收入：
利息收入			98				3
其他的收入			35				80
其他收入总额			133				83
净利		$	1,762			$	1,339
每股普通股收益：
基本的		$	0.02			$	0.02
稀		$	0.02			$	0.02
已发行普通股的加权平均数：
基本的			86,720,823				86,066,070
稀			86,720,823				86,066,070

PEDEVCO CORP.
合并现金流量表
（单位：千）

		截至 3 月 31 日的三个月，
		2023年				2022年
经营活动产生的现金流量：
净利		$	1,762			$	1,339
调整净利润与经营活动提供的净现金：
折旧、消耗、摊销和增值			2,581				1,886
使用权资产摊销			26				24
股权激励费用			518				第563章
经营资产和负债的变化：
应收账款——石油和天然气			(3,358	）			(2,188	）
预付费用和其他流动资产			100				109
应付账款			35				（94	）
预提费用			136				（243）	）
应付收入			(18	）			19
经营活动提供的现金净额			1,782				1,415
投资活动产生的现金流量：
支付钻井和完井费用的现金			(17,032	）			(5,508	）
车辆支付现金			(41	）			”
投资活动使用的现金净额			(17,073	）			(5,808	）
现金、现金等价物和限制性现金净减少			（15,291	）			(4,093	）
期初现金、现金等价物和限制性现金			32,977				29,227
期末现金、现金等价物和限制性现金		$	17,686			$	25,134
现金流量信息补充披露
现金支付：
兴趣		$	”			$	”
所得税		$	”			$	”
非现金投资和融资活动：
应计石油和天然气开发成本的变化		$	10,534			$	173
资产报废成本估计的变化（净值）		$	6			$	45
发行限制性普通股		$	1			$	1

归属于 PEDEVCO Corp. 的净利润（亏损）与息税折旧摊销前利润 (EBITDA) 和调整后 EBITDA*（单位：千）的调节表

		截至 3 月 31 日的三个月，
		2023年				2022年
净利		$	1,762			$	1,339
加（减）
折旧、消耗、摊销和增值			2,581				1,886
息税折旧及摊销前利润			4,343				3,225
加（减）
股权激励			518				第563章
调整后息税折旧摊销前利润		$	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 鈥淯se of Non-GAAP Financial Information鈥�, 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

Nasdaq

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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.

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鈥榮 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鈥檚 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鈥檚 outlook on Monday, while its forecasts for next week were lower.

BOE Report

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

CALGARY, AB, March 1, 2023 /CNW/ 鈥� Tamarack Valley Energy Ltd. (鈥�Tamarack鈥� or the 鈥�Company鈥�) 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鈥檚 year end independent oil and gas reserves evaluation as of December 31, 2022 (the 鈥�Reserve Report鈥�), prepared by Tamarack鈥檚 independent qualified reserves evaluator, GLJ Ltd. (鈥�GLJ鈥�).

Selected reserves, financial and operating information is outlined below. Selected financial and operating information should be read with Tamarack鈥檚 audited annual consolidated financial statements and related management鈥檚 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鈥檚 website at www.tamarackvalley.ca. The Company鈥檚 Annual Information Form (AIF) for the year ended December 31, 2022  is available on SEDAR and the Company鈥檚 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. (鈥�Deltastream鈥�) 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鈥檚 enhanced shareholder return framework.

2022 Reserve Highlights

The ongoing positive impact of Tamarack鈥檚 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鈥檚 proved developed producing (PDP), total proved (TP) and total proved plus probable (TPP) reserves from the Reserve Report are highlighted below.

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

Financial & Operating Results

Reserves Snapshot by Category

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

2023 Outlook

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

Operations Update

Clearwater

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

Nipisi development for 2023 will focus on continued waterflood expansion across the field. Multilateral injection wells and extended reach waterflood patterns are being implemented to enhance waterflood capital efficiencies. Production for the first three weeks of February averaged 12,500 boe/d⁽¹⁰⁾ and construction of the second phase of Tamarack鈥檚 Nipisi gas conservation project is expected to be complete by the end of the first quarter.鈥� Upon completion Tamarack anticipates having over 90% of its Nipisi solution gas conserved. In support of ongoing development, expansion of Tamarack鈥檚 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鈥檚 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鈥檚 West Nipisi waterflood design. The wells continue to clean up, but recent production has been over 700 bopd from the pad.  Tamarack has one drilling rig running in West Marten at the 11-10-076-05W5 pad with three oil wells rig released to date, and another six planned wells before breakup. The first two wells from the 11-10 pad site are expected to commence production in the first half of March.  West Marten production rates have averaged 1,900 boed/d⁽¹¹⁾ for the first three weeks of February and are expected to continue to climb as existing wells are optimized and new wells are brought on stream.  Tamarack is currently evaluating gas conservation in West Marten and will provide further updates throughout the year.

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

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

Charlie Lake

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

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

Exploration/Delineation Update

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

Clearwater

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

Board of Directors Changes

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

Risk Management

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

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

2022 Independent Qualified Reserve Evaluation

The following tables highlight the findings of the Reserve Report, which has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 鈥� Standards of Disclosure for Oil and Gas Activities (鈥�NI 51-101鈥�) 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 鈥淣et Present Values of Future Net Revenue Before Income Taxes Discounted鈥� 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 鈥�3-Consultant Average Forecast Pricing鈥�). It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. All per share reserves metrics below are based on basic shares outstanding as of December 31, 2022.

Company Reserves Data (Forecast Prices and Costs)

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

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

Future Development Capital Costs⁽²¹⁾

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

Finding, Development & Acquisition Costs

About Tamarack Valley Energy Ltd.

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

Abbreviations

Reader Advisories

Notes to Press Release

Disclosure of Oil and Gas Information

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

References in this press release to 鈥渃rude oil鈥� or 鈥渙il鈥� refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to 鈥淣GL鈥� throughout this press release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51-101. References to 鈥渘atural gas鈥� 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 鈥渇orward-looking statements鈥�) within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as 鈥済uidance鈥�, 鈥渙utlook鈥�, 鈥渁nticipate鈥�, 鈥渢arget鈥�, 鈥減lan鈥�, 鈥渃ontinue鈥�, 鈥渋ntend鈥�, 鈥渃onsider鈥�, 鈥渆stimate鈥�, 鈥渆xpect鈥�, 鈥渕ay鈥�, 鈥渨ill鈥�, 鈥渟hould鈥�, 鈥渃ould鈥� or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack鈥檚 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鈥檚 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鈥檚 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鈥檚 expectations; risk management activities, Tamarack鈥檚 commitment to ESG principles and sustainability; and the source of funding for the Company鈥檚 activities including development costs. Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the Company鈥檚 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鈥檚 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鈥檚 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 鈥渞eserves鈥� 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鈥檚 properties; the characteristics of recently acquired assets, including the Deltastream assets; the successful integration of recently acquired assets into Tamarack鈥檚 operations; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company鈥檚 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鈥檚 geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack鈥檚 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鈥檚 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鈥檚 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鈥檚 AIF and the management discussion and analysis for the period ended December 31, 2022 (the 鈥�MD&A鈥�) for additional risk factors relating to Tamarack, which can be accessed either on Tamarack鈥檚 website at www.tamarackvalley.ca or under the Company鈥檚 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, 鈥�FOFI鈥�) 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鈥檚 future business operations. Tamarack and its management believe that FOFI has been prepared on a reasonable basis, reflecting management鈥檚 best estimates and judgments, and represent, to the best of management鈥檚 knowledge and opinion, the Company鈥檚 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鈥檚 guidance. The Company鈥檚 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 (鈥淚FRS鈥�) and, therefore, may not be comparable with the calculation of similar measures by other companies.

鈥淎djusted funds flow (capital management measure)鈥� 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鈥檚 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鈥檚 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.

鈥淔ree funds flow (previously referred to as 鈥渇ree adjusted funds flow鈥�) and Capital Expenditures (capital management measure)鈥�. 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鈥檚 ability to improve returns and to manage the long-term value of the business.

鈥淣et 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)鈥� 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鈥檚 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鈥檚 netbacks per boe to the most directly comparable measure presented in accordance with IFRS.

鈥淣et debt (capital management measure)鈥� 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.

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

SOURCE Tamarack Valley Energy Ltd.

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

Oil Price

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

 

Cheniere (NYSEAMERICAN: LNG) reported today total revenues of $33.428 billion for 2022, up from $15.864 billion for 2021. Last year鈥檚 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鈥檚 zero-Covid policy and high prices that south Asian LNG importers couldn鈥檛 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.

鈥淓urope had to compete for LNG cargoes resulting in unprecedented price spikes,鈥� Cheniere said in the comments on the market environment in its SEC filing.

鈥淭his 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,鈥� 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 (鈥淧ermian Resources鈥� or the 鈥淐ompany鈥�) 鈥�

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

DENVER, Feb. 22, 2023 (GLOBE NEWSWIRE) 鈥� PDC Energy, Inc. (鈥淧DC鈥� or the 鈥淐o鈥�

Coterra Energy Inc. (NYSE: CTRA) (鈥淐oterra鈥� or the 鈥淐ompany鈥�) today鈥�

Oil and Gas 360

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

 

• Substantial growth in profitability. Net income for the full year 2022 and fourth quarter 2022 was $1.11 billion and $258.5 million, or $8.96 and $2.09 per diluted common share, respectively. Adjusted net income⁽¹⁾ for the full year 2022 and fourth quarter 2022 was $7.29 and $1.29 per diluted common share, respectively.
• Increased return of capital to stockholders through share buybacks and fixed dividend. The Company repurchased 1,365,255 shares from announcement of its return of capital program on September 7, 2022 through year-end and initiated payment of the $0.15 quarterly dividend on November 7, 2022.
• Proved reserves growth. Estimated proved reserves at year-end 2022 totaled 537 MMBoe, a 9% increase from year-end 2021, replacing 2022 production by 205%. The ratio of estimated proved reserves at year-end 2022 to 2022 production is 10.1 years. The standardized measure of discounted future net cash flows from estimated proved reserves was $9.96 billion, up 43% from year-end 2021.
• Significant cash flow generation. For the full year 2022, net cash provided by operating activities of $1.69 billion before net change in working capital of $72.1 million totaled $1.76 billion.⁽¹⁾ Fourth quarter net cash provided by operating activities of $288.4 million before net change in working capital of $58.8 million was $347.2 million.⁽¹⁾ For the full year 2022, the Company generated Adjusted free cash flow⁽¹⁾ of $848.7 million, more than double the Adjusted free cash flow generated in 2021.
• Production at high end of guidance. Production for the full year 2022 was 53.0 MMBoe or 145.1 MBoe/d, up 3% from 2021. Fourth quarter production was 13.1 MMBoe or 142.9 MBoe/d.
• Strengthened balance sheet. Cash and cash equivalents at year-end 2022 were $445.0 million. Utilizing cash generated in 2022, and in support of the Company鈥檚 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鈥檚 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鈥檚 track record of inventory replacement and growth, applying the Company鈥檚 differential strength in geosciences and development optimization.

Chief Executive Officer Herb Vogel comments: 鈥淲e 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.鈥�

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鈥檚 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鈥檚 previous peak of 297 MMBoe, set at the end of 2021.

STANDARDIZED MEASURE

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

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

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

 

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

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

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

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

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

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

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

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

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

FINANCIAL POSITION, LIQUIDITY AND CAPITAL EXPENDITURES

At year-end 2022, the outstanding principal amount of the Company鈥檚 long-term debt was $1.59 billion with zero drawn on the Company鈥檚 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鈥檚 borrowing base and commitments under its senior secured revolving credit facility were $2.50 billion and $1.25 billion, respectively, providing $1.70 billion in available liquidity.

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

Commodity hedge positions as of February 15, 2023:

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

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

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

KEY ASSUMPTIONS

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

GUIDANCE FULL YEAR 2023:

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

GUIDANCE FIRST QUARTER 2023:

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

EARNINGS Q&A WEBCAST AND CONFERENCE CALL

February 23, 2023 鈥� 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鈥檚 website at ir.sm-energy.com or by telephone. In order to join the live conference call, please register at the link below for dial-in information.

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

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

CONFERENCE PARTICIPATION

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

FORWARD LOOKING STATEMENTS

This release contains forward-looking statements within the meaning of securities laws. The words 鈥渄eliver,鈥� 鈥渄emonstrate,鈥� 鈥渆stablish,鈥� 鈥渆stimate,鈥� 鈥渆xpects,鈥� 鈥済oal,鈥� 鈥済enerate,鈥� 鈥渕aintain,鈥� 鈥渙bjectives,鈥� 鈥渙ptimize,鈥� 鈥渢arget,鈥� 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鈥檚 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鈥檚 ESG stewardship goals. These statements involve known and unknown risks, which may cause SM Energy鈥檚 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鈥檚 most recent Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company鈥檚 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鈥檚 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 鈥淒efinitions of non-GAAP Measures and Metrics as Calculated by the Company鈥� section in Financial Highlights for additional information.

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

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

 

 

 

 

 

To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), the Company provides certain non-GAAP measures and metrics, which are used by management and the investment community to assess the Company鈥檚 financial condition, results of operations, and cash flows, as well as compare performance from period to period and across the Company鈥檚 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鈥檚 financial or operating performance presented in accordance with GAAP. A reconciliation of the Company鈥檚 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鈥檚 Credit Agreement, a material source of liquidity for the Company, based on Adjusted EBITDAX ratios. Please reference the Company鈥檚 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鈥檚 ongoing operational results and trends and believes these measures provide useful information to investors for analysis of the Company鈥檚 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鈥檚 ability to internally fund its capital expenditures, to service or incur additional debt, and to measure management鈥檚 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鈥檚 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鈥檚 Credit Agreement. The Company and the investment community may use this metric in understanding the Company鈥檚 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鈥檚 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鈥檚 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.

 

 

 

 

 

 

 

消息来源 SM 能源公司