作者：高级编辑 Stephen Whitfield

Sarah Fenton 是 EQT 公司上游业务的执行副总裁。

您认为目前该行业面临的最大挑战是什么？

我认为我们对这个问题持更乐观的态度。作为运营商，我们始终关注天然气需求。谁在寻找我们的分子？这不仅仅是行业对天然气的总体需求，更是EQT特有的天然气需求。我们目前已经看到了强劲的市场信号。当我们谈到挑战时，我们更多地想到的是EQT分子需求带来的机遇。

我们的主要基地——阿巴拉契亚盆地——在某种程度上受到限制。我的意思是，阿巴拉契亚盆地的天然气分子，无论是在马塞勒斯页岩气层还是尤蒂卡页岩气层，都倾向于留在盆地内。虽然有出口可以将它们输送到墨西哥湾沿岸或东海岸，但由于过去几年监管和许可方面的挑战，这些出口已被大幅减少或取消。我们一直在寻找盆地内的需求，将其作为我们增长的来源之一。

如果没有这种增长，我们只能维持基本产量不变，老实说，我们长期以来一直如此：通过收购实现增长，维持基本产量不变。

展望2026年，EQT预计盆地内需求将出现可观的增长，这主要得益于新建数据中心、新建发电厂，甚至液化天然气项目。将这些需求信号与我们自身构建的稳健上游业务相结合，这是一个好兆头。

你是如何培养这种韧性的？

过去几年，我们一直致力于降低成本和实现运营脱碳。2024年，我们宣布成为全球首家在范围1和范围2的基础上实现净零排放的大型传统能源公司。

除此之外，我们还进行了大量收购。在过去的六年里，我们承销了近 200 亿美元的交易，并深入了解了我们的库存——层级、经济效益和结果范围——这确实帮助我们提升了库存质量。

您提到您对阿巴拉契亚地区的需求增长持乐观态度。您对该地区生产商满足这种需求增长的能力有多乐观？

从EQT的角度来看，我认为我们已经做好充分准备来满足这一需求。这背后的一个重要原因是我们专注于垂直整合：收购Equitrans后，我们成为该地区唯一一家大规模垂直整合的运营商，这意味着我们的上游和中游业务协同运作。这使我们能够掌控自己的命运。我们可以对天然气价值链的各个环节进行投资。

当我们谈到收购带来的协同效应时，我们显然会谈到后台协同效应，但实际上也存在真正的运营协同效应。

我们在阿巴拉契亚山脉拥有大片土地的使用权，并且每年积极开发约 150 万英尺的横向输油管道——现在我们的中游业务遍及宾夕法尼亚州、西弗吉尼亚州、俄亥俄州，一直延伸到卡罗来纳州，这使我们能够接触到价值链上不同的需求中心。

当上游和中游业务整合在一起时，基本上就相当于在一个屋檐下进行统筹管理，所有人的目标都一致——运营安全、卓越运营和资本效率。因此，在规划油井、集输系统以及新的需求中心时，我们可以进行整体规划。对于新的需求客户，他们无需再分别与上游人员、集输公司和压缩机供应商等进行谈判，只需与EQT公司沟通即可——我们涵盖了从井口到销售点的整个流程，作为一个精简高效的团队运作。

那么，垂直整合究竟意味着什么？它本质上意味着我们可以降低天然气运输成本。我们在钻井和中游环节都提高了资本效率。这有助于我们在满足需求的同时保持库存，并通过成本效益实现这一目标——这是一项巨大的胜利。

例如，在决定将资金投入到一组减压项目或钻探新井以维持产量时，我们可以做出最有资本效率的决定——这些减压项目的资本效率比开发新井高 10-20%，因此我们可以选择减压项目，在保持库存的同时，仍然能够提供相同的产量。

您能否详细说明一下中游业务是如何帮助您在上游业务中提高效率的？

首先想到的就是提前采购管道等长周期物料的能力。与业务伙伴签订合同至关重要。想想看，要找到承包商或其他执行这些交易所需的人员，这需要很长时间。当我们把中游和上游业务整合在一起时，我们就能在统一的预算和资金约束下协同运作。我们还可以着眼长远，规划未来的资金投入方向。

我们目前在完井作业方面更多地实现了这些协同效应。完井作业需要大量的天然气和水，以及输送这些资源的管道。我们的压裂设备全部采用电力驱动。这些电动涡轮机需要大量的天然气，而压裂作业本身也需要水。确保天然气和水都能按时按量供应有助于最大限度地减少停机时间，但拥有所有这些设备的成本非常高昂。即使不使用，仅仅为了保证设备和人员在现场，每小时也要花费数千美元。停机时间越少，对运营商而言越有利，因为可以节省成本；对承包商而言，也能提高设备和人员的利用率。

当我们掌控中游环节时，我们可以说：“两年后我们需要X量的水和X量的燃气，所以我需要建造X条管道来输送这些水和燃气。” 水和燃气供应的规划和审批需要时间，而且你需要准备好相应的供应链 来支持这些需求。通过掌控中游环节的建设和运营，我们能够更好地进行规划，从而提高整体资本效率。

从钻井角度来看，我们正在推进道路和井场建设。在阿巴拉契亚地区，必须修建道路才能支持重型设备的运输。这里是山区，所以建设成本可能很高。如果在二叠纪盆地修建道路或井场只需几百万美元甚至更少，那么在阿巴拉契亚地区，成本可能翻三四倍。这是一笔巨款。提前规划井场和道路建设，并沿着我们的中游通道进行长期规划，是提高资本效率的关键。

此外，还有监管方面的问题。毫无疑问，管道输水是最安全、最经济、最可靠的输水方式。在阿巴拉契亚地区，有些地方禁止管道输送采出水，这就要求我们用卡车运输采出水——这既昂贵又危险。天气好的时候，我们用卡车大概每分钟可以输送10桶水——但我们的压裂产量高达每分钟100桶。我们需要弥补这个缺口。将中游和上游环节整合起来，确实有助于我们更好地协调水和燃料气供应链与管道规划。

听起来，与二叠纪盆地相比，在阿巴拉契亚地区开展业务有很多限制。你所说的这种垂直整合模式，未来在那里开展业务是否必要？

我未必会那样说。很多大型企业并没有像我们这样实现高度整合。但是，当业务部门合并时，就能看到规模经济效益。

为了更好地理解背景，不妨看看Equitrans被收购前的情况。作为一家中游公司，Equitrans的资本支出完全局限于中游业务。而作为一家纯粹的上游公司，Equitrans当时面临的问题是，天然气流入的是高压系统，这会导致天然气在高压下流动时，油井实际上被堵塞了。我们始终无法说服Equitrans额外投入资金来增加系统压缩装置，或者增设一两条管线来降低压力。

现在，由于我们拥有了整合的上游和中游业务，我们可以从更全面的角度做出决策。仅去年一年，我们就实现了 6000 万美元的资本协同效应，预计未来几年还将达到 2.5 亿美元。例如，投资建设中央压缩设施可以让我们节省数百万美元的钻井成本。对于一家单纯的中游公司来说，这些节省可能微不足道。但由于我们现在能够优化整个系统，因此能够看到这些成本节约。

此外，我们还可以考虑一些目前可能尚未实现的增长项目。例如，某个水务或燃气系统或许能够帮助我们在几年内满足需求。我们可以研究这些项目如何能够提升整个业务的资本效率，而不仅仅是上游或中游环节。这会产生协同效应。

您提到EQT拥有100%电动压裂车队。在我们竭尽所能减少碳排放的时代，您认为电动车队是完井作业的“必备条件”吗？

我不会把它称为“必备品”，但这确实是明智的商业决策。我们是一家大型天然气生产商，我们希望能够充分利用我们的产品，无论是用于加热储罐、为压缩站供电，还是为压裂设备供电。将我们的产品用作燃料至关重要。

水力压裂是耗气耗电的重型作业之一。我们希望能够提供这些能源。显然，对我们来说，使用自己的天然气比从其他地方购买更经济。

此外，与传统的柴油压裂车队相比，电动压裂车队的碳排放量更低。从成本和排放的角度来看，这无疑是一项明智的商业决策。

这些电气设备更易于维护，运行时间更长，从而降低了成本。我们在上游作业中始终秉持安全、成本和性能至上的原则——我们每天都这样做。更安全的作业环境意味着更高的作业效率和性能，最终降低每英尺成本。

您提到了EQT在实现净零排放方面所做的工作。电子压裂技术是帮助您实现这一目标的关键因素吗？

这是关键组成部分之一，但我们也做了其他事情。我们采取了审慎的方法，重点是从源头减少排放。对我们来说，这意味着减排。

我们的一项旗舰项目是全面更换了我们所有运营区域内超过8000台天然气气动装置。这是一个成本相对较低的项目，却显著降低了我们的排放量和排放强度。我们亲切地称之为“气动装置更换闪电战”，因为我们希望在一定时间内（两年以内）实现排放目标，但我们最终在不到18个月的时间内安全地完成了这项任务。我们为此感到非常自豪。事实上，我们还专门撰写了一份白皮书，希望业内其他企业也能借鉴这一成功经验。

我们也参与了阿巴拉契亚甲烷倡议。作为该倡议的一部分，我们进行了近15000次航拍调查，覆盖面积达20500平方英里，以绘制我们的排放地图。我们使用了先进的监测系统来实时追踪我们的排放情况。我们必须确保有一个可靠的来源来报告所有排放数据。

我们也是 Context Labs 的股权投资者，该公司致力于提供透明、可追溯且可审计的碳排放核算方案。Context Labs 正与大型审计公司毕马威 (KPMG) 紧密合作，共同开发用于报告所有这些信息的软件和工具。

将航空测量与我们的电动压裂车队、气动设备更换以及现在的 Context Labs 结合起来，您就可以全面了解碳排放报告。

当然，仍有一些残留排放物我们可以消除，因此我们专注于本地项目。我们积极参与的项目之一是西弗吉尼亚州的土壤监测技术、植树造林和生态修复工作。我们利用西弗吉尼亚大学和西弗吉尼亚州林业局的资源，产生具有实际环境价值和社区效益的碳抵消额度。

所有这些的共同之处在于，我们将所有减排都视为对业务有益的事情。我们不只是进行报告，而是进行测量、采取行动、验证，并不断迭代改进。正是这种做法使我们能够实现上游范围 1 和范围 2 的净零排放，也正是我们计划在业务持续增长的同时保持这一目标的方式。

您认为运营商和钻井承包商可以通过哪些方式更有效地合作？

我其实想把这个问题扩大一下。这不仅指钻井承包商，还包括我们所有的上游服务提供商，这不仅包括钻井和完井，还包括我们在现场使用的所有服务。我们特意称他们为业务合作伙伴，而不是服务提供商。

仅仅两个词——服务提供商和业务伙伴——就能带来如此巨大的差别，而这正是我们内心的真实感受。让我们面对现实吧：他们才是真正把事情落实到实处的人。他们才是真正奔波在前线的人。

对我们而言，真正的双赢源于三点：规模、稳定性和协同效应。EQT能够带来大规模开发。我们拥有清晰、稳定且为期多年的开发计划。该计划支撑着我们的开发规划、资本配置和储备。我不知道其他运营商是否也能做到这一点，但这确实能让我们的合作伙伴提高人员和设备的利用率。

作为回报，我们可以享受更低的成本和更好的性能，因为它们可以证明投资于技术、培训和围绕我们长期计划的持续改进是合理的。

纵观目前石油行业钻探的油井，您认为我们是否充分利用了它们的储量？如果没有，您认为哪些技术可以帮助我们提高储量？

作为工程师和科学家，我们永不满足。我们总是希望从油井中获得更多产出。提高油井产能的关键在于两大要素：提高采收率和延长作业时间。在过去的50年里，现代增产技术使我们得以采出大约一半的天然气储量。这意味着还有一半的天然气仍然埋藏在地下。我们仍然让大量的天然气留在地下。

问题是，我们如何提高恢复率，或者如何在最短的时间内提高恢复率？

一些新型井下诊断技术将成为关键工具，帮助我们真正了解所谓的增产岩体体积（SRV），以及裂缝的扩展方式、母子裂缝和邻井裂缝的相互作用，以及这些因素可能对井筒设计产生的影响。如果我们能够更深入地了解地下情况，就能更好地调整井距、完井设计，甚至优化井筒改造策略，从而使每一美元的投入都能回收更多的岩浆分子。

对我们来说，第二个关键因素是正常运行时间，也就是油井的出油频率。首先要看流量计是否在运转。理想情况下，只要油井有油，流量计就应该运转。我们几乎所有的生产井都位于横跨三个州的山区，因此，监测流量需要改进遥测技术，以便我们能够实时读取山区油井的流量数据。

我们还利用边缘设备来实现这一点。拥有实时SCADA系统可以避免重大延迟，从而实现实时分析和实时变更，而不是分钟级、小时级甚至天级的延迟。现代预测模型将使我们能够进行更远程的操作，并在设备问题演变成停机事件之前预测它们，但我们尚未完全实现这一点。

这是我们正在探索的人工智能领域。人工智能尚处于起步阶段，我们正在努力了解如何运用人工智能来提高设备正常运行时间。例如，如果我知道三周后这口井会因为液载而停产，或者这口井的油管磨损严重，或者油管出现破损，我就可以在井停产之前就发出工作指令、订购材料并准备好修井设备。这是我们的目标之一。

在探索人工智能在石油领域应用的过程中，您希望重点关注哪些方面？

我们认为人工智能是工程师和科学家的助力，而不是他们的替代品。我认为它的真正价值在于更快、更数据驱动、更具预测性的决策。我们现在对人工智能的理解是，与其试图解决所有问题，不如将其分解成简单、重复性的任务。人工智能可以帮我们做哪些家务？我们不想洗衣服，也不想洗碗；我们更愿意去粉刷墙壁或打理花园。那么，我们如何才能让人工智能帮我们洗碗和洗衣服呢？

将这些类比应用到油田，我们如何监测成千上万口油井、成千上万台压缩机以及所有不同的设备，并寻找那个会偏离正常范围的因素呢？

我们希望人工智能能够持续监控，当刀具开始变脏时，它能及时发出警告并提出处理建议。然后，我们的人员可以介入，运用智能工程判断来决定如何操作。未来可能会出现不同的人工智能模型，实时优化参数，以最大限度地减少振动、粘滑、钻头跳动或钻速。我们目前尚未实现这一点，但以上是一些示例。

对于完井作业，我们显然需要对数千个井段进行模式识别。这不仅包括各井段的处理压力和速率，还包括我们从地质导向工具获取的一些实时信息，这些信息可以帮助我们了解岩体情况，从而推荐合适的泵送方案、流体系统或问题区域。这些都是我们尝试在完井作业中利用人工智能技术的一些领域，但目前仍处于起步阶段。

在所有这些案例中，人工智能只是更早地发现问题，列出一些可行的方案，然后我们的工程师和科学家团队可以选择在安全性、可靠性和经济性之间取得最佳平衡的路径。我们才刚刚开始探索这个问题，团队正在深入研究如何才能真正实现自主运行。

在一些非常规油气盆地，水平井长度持续增长，3英里和4英里的水平井正迅速成为常态。您如何看待这一趋势？您认为业界会继续寻找延长油井长度的方法吗？

我认为我们还能走得更远。目前限制我们的是钻机和压裂技术。只要钻机和技术性能优异，我们就能继续钻探更长的井眼。压裂方面也是如此：水平井眼越长，就越需要精心设计压裂趾部，才能获得良好的压裂效果和增产效果。

无论是地面上的设备——无论是 10,000 psi 的设备，还是我们现在正在泵送的 15,000 psi 的设备，亦或是我们将来最终需要的 25,000 psi 的设备——我们都将继续改进技术，以便能够到达那些长水平井。

在同一井眼内钻探更长的井段总能降低每英尺成本，因为可以将井场、地面位置、道路建设和垂直段的成本（这些成本或多或少都是一次性成本）分摊到更长的生产井段上。这样既能防止浪费，又能最大限度地减少对地面的影响，同时还能高效地开发油藏。只要能够安全地钻探、完井和生产这些超长水平井段，并且有关钻井和井距单元的监管框架能够随着技术的发展而不断完善，这种趋势就会持续下去。

在钻井方面，随着钻机技术的不断进步，我们的定向和地质导向工具的速度越快、响应越灵敏，我们就能获得更准确的实时数据。我们希望利用智能地质导向技术，在数英里的钻井作业中始终保持在目标区域内。

在完井方面，我们需要更高耐压等级的设备，并且需要改进材料以控制摩擦压力损失。摩擦压力是水力压裂的敌人。开发能够最大限度减少摩擦、从而最大限度提高井下压力的流体技术将是另一个重要环节。

By Stephen Whitfield, Senior Editor

Sarah Fenton is Executive VP of Upstream at EQT Corp.

What do you see as the biggest challenges facing the industry right now?

I think we’d take a more optimistic view to that question. For us as an operator, we’re always looking at our gas demand. Who’s looking for our molecules? It’s not so much just the general demand for natural gas from the industry but EQT-specific gas demand. We’re seeing strong signals right now in our backyard. When we talk about challenges, we think more about the opportunities around the demand for EQT molecules.

Appalachia – where we’re primarily based – is somewhat constrained as a basin. What I mean by that is, the molecules in Appalachia, whether they’re in the Marcellus or the Utica, tend to stay in the basin. There are outlets to get them out to the Gulf Coast or East Coast, but they’ve been minimized or canceled due to regulatory and permitting challenges over the past several years. We’re constantly looking for in-basin demand as one of our sources of growth.

Without that growth, we’re just holding our base production flat, and honestly that’s where we’ve been for a long time: growing through acquisitions, holding that base production flat.

Looking into 2026, at EQT we’ve seen decent in-basin demand growth coming our way from new data centers, new power generation or even LNG. When you combine those demand signals with the resilient upstream business we’ve built for ourselves, it’s a good sign.

How have you built that resilience?

We’ve spent the past couple of years driving our costs down and decarbonizing our operations. In 2024, we announced we had become the first traditional energy company of scale in the world to achieve net zero on a Scope 1 and Scope 2 basis.

On top of that, we’ve done a lot of acquisitions. We’ve underwritten nearly $20 billion in deals in the last six years and have taken a deep dive in understanding our inventory – tier, economics and ranges of outcomes – and that’s really helped us high-grade our inventory.

You mentioned your optimism around demand growth in Appalachia. How optimistic are you about the ability of producers in the region to meet that demand growth?

From EQT’s perspective, I think we’re really set up well to meet that demand. A big reason behind that is our focus on vertical integration: After our acquisition of Equitrans, we became the only vertically integrated operator at scale in the region, meaning that we have an upstream and midstream business working together. This allows us to be in control of our own destiny, so to speak. We can invest across the natural gas value chain.

When we talk about some of the synergies that come from an acquisition, obviously we talk about the back-office synergies, but then there are also real operational synergies.

We have the rights to a lot of acreage in Appalachia and are actively developing about a million and a half lateral feet a year – and now we have a midstream footprint spreading across Pennsylvania, West Virginia, Ohio and all the way down to the Carolinas, which allows us to access different demand centers along that value chain.

When you bring the upstream and the midstream together, you basically align it under one roof, and everybody has the same goals – operational safety and excellence, and capital efficiency. So, when we plan our wells, when we plan the gathering and when we plan these new demand centers, we can do it holistically. And for new demand customers, instead of having to negotiate with an upstream person, a separate gathering company and a separate compressor provider, and so on, you can just talk to EQT – we’ve got the wellhead to sales point covered, operating as one team streamlined.

What does vertical integration mean, then? It essentially means that we can lower the cost to move our gas. We’ve gained in capital efficiency, both on the drilling and midstream sides. This helps us preserve inventory while still meeting demand through cost efficiency – that’s a huge win.

For example, when deciding to spend capital on, say, a group of pressure-reduction projects or drilling new wells to maintain production, we can make the most capital-efficient decision – those pressure-reduction projects are 10-20% more capitally efficient than developing a new well, so we can choose the pressure-reduction projects and preserve our inventory while still delivering the same production.

Can you elaborate on any examples where the midstream business has helped you realize efficiency gains in upstream?

One of the first things that comes to mind is the ability to get ahead of long lead items, like pipes. Getting those contracts in place with our business partners is important. When you think about the contractors, or the other folks that are going to be needed to execute those deals, it takes a long time. When we have midstream and upstream together, we’re aligned under one set of budgets and capital constraints. We can also take that long-term view of where we’re going to spend capital.

We’re realizing more of those synergies on the completions side right now. Completions need a lot of gas and water, and the pipes to deliver it. Our frac fleet is 100% electric. Those electric turbines need a lot of gas, and the frac job needs water. Having both delivered on time and on rate helps to minimize downtime, but having all of that equipment is very expensive. Even if you’re not using it, you’re spending thousands of dollars per hour just to have that equipment and staff on site. The less downtime, the better that is for both the operator in cost savings and the contractor for high utilization rate of the equipment and staff.

When we’re in control of the midstream, you can say, “we’re going to need X amount of water and X amount of fuel gas in two years, so I need to build X amount of pipe for that water and gas.” Planning and permitting for the water and fuel gas supply takes time, and you need to have that supply chain ready to support that. Our ability to plan better with control of midstream construction and operations enables us to improve overall capital efficiency.

From a drilling perspective, we’re working through road and pad builds. You have to build the roads in Appalachia to support the heavy equipment mobilization. We’re a mountainous region here, so that can be an expensive proposition. If building a road or pad in the Permian is a few million dollars or less, in Appalachia that cost could triple or quadruple. That’s a lot of money. Getting ahead of that process and performing long-term planning of pad and road builds alongside our midstream right-of-ways is key to capital efficiency.

There’s also a regulatory aspect. Piping water is hands down the safest, cheapest and most reliable way to move water. In Appalachia, there are some areas where piping produced water is prohibited, which requires us to move our produced water by truck – and that’s expensive and dangerous. On a good weather day, we could probably deliver 10 barrels a minute with trucks – but we frac on the order of 100 barrels a minute. We need to make up for that gap. Having the midstream and the upstream together really helps support a lot of that to align our water and fuel gas supply chain with pipeline planning.

It sounds like you have a lot of constraints working in Appalachia compared with, say, the Permian Basin. Is the kind of vertical integration you’re talking about necessary for doing business out there in the future?

I wouldn’t put it that way necessarily. There are a lot of big players out here that aren’t integrated in the way we are. But when you combine business units, you see the economies of scale.

To give a little context, look at a company like Equitrans before the acquisition. As a midstream company, it focused on capital spending through one lens – the midstream lens. EQT as a sole upstream company was getting to a point where our gas was flowing into higher-pressure systems, which effectively chokes the wells when the gas has to flow against high pressures. We could never get Equitrans to spend that extra money to add system compression, or add one or two additional lines, to keep those pressures down.

Now, since we have an integrated upstream and midstream business, we can make that decision on a more holistic basis. This past year alone, we’ve seen $60 million in capital synergies, with an anticipated $250 million over the next few years. For example, spending money to add central compression allows us to save millions on drilling wells. Those savings wouldn’t mean anything to a company that’s just a midstream company. But because we’re able to optimize the whole system now, we can see those cost savings.

Also, we can look at growth projects that we might not realize today. There may be a water or gas system that could set us up to meet demand in a few years. We can look into how those projects might make the entire business, not just upstream or midstream independently, more capitally efficient. That’s synergistic.

You mentioned EQT having a 100% electric frac fleet. In an era where we’re looking to reduce our emissions footprint however we can, do you find electric fleets as a “must-have” for completions?

I wouldn’t necessarily call it a “must-have,” but it’s just good business. We’re a large natural gas producer, and we want to be able to use our product, whether that’s heating tanks, electrifying our compressor stations or electrifying our frac fleet. Using our product as a fuel is important.

Frac is one of those heavyweight services that uses a lot of gas and electricity. We want to be the one to provide that. Obviously, it’s cheaper for us to use our own gas instead of buying it from somebody else.

Additionally, the carbon emissions associated with electric frac fleets compared with conventional diesel fleets are better. It’s just good business from a cost and emissions standpoint.

That electrical equipment is also easier to maintain and has better uptime, which translates to improved costs. Our mantra in upstream is safety, cost and performance – that’s all day, every day. When we have safer operations, that translates into higher-performing operations and more efficiency, which ultimately translates into a lower cost per foot.

You mentioned EQT’s work in reaching net zero. Was e-frac the key component to help you realize that?

It was one of the key components, but we’ve done other things, as well. We’ve taken a deliberate approach to this, with a heavy focus on reducing emissions at the source. For us, this means abatement.

One of our flagship efforts was the full-scale replacement of more than 8,000 natural gas pneumatic devices across our entire operating footprint. This was a pretty low-cost project that drove a step change in the reduction of our emissions and emissions intensity. We affectionately called this “The Pneumatic Device Replacement Blitz,” because we wanted to achieve emissions goals within a certain amount of time – in under two years – but we did it in under 18 months, safely. We are pretty proud about that. In fact, we wrote a white paper about it because we want others in the industry to replicate that playbook.

We also participated in the Appalachia Methane Initiative. As part of that effort, we’ve done nearly 15,000 aerial surveys over 20,500 square miles to map our emissions. We’ve used advanced monitoring systems to track our emissions in real time. We have to make sure that we have a trusted source for reporting all of the emissions.

We’re also an equity investor in Context Labs, which I would describe as transparent, traceable and auditable carbon accounting for emissions. Context Labs is working closely with KPMG, a large auditing firm, as we develop the software and the tools to report all of this.

When you combine the aerial surveying with our electric frac fleets, our pneumatic device replacement and now Context Labs, you have that full-cycle view on carbon emissions reporting.

Of course, there are residual emissions that we can’t eliminate yet, so we focus on local projects. One in which we’re actively involved is the soil monitoring technology and tree planting and restoration efforts in West Virginia. This is leveraging the University of West Virginia and the Forestry Service of West Virginia to generate carbon offsets that have real environmental value and community benefits.

The common thread with all of this is that we treat all emissions reductions as something that’s good for business. Rather than just engaging in a reporting exercise, we measure, we act, we verify and we keep iterating to improve that. That’s what has allowed us to reach net zero Scope 1 and 2 emissions for upstream, and that’s how we plan to stay there while continuing to grow the business.

In what ways do you think operators and drilling contractors can work together more efficiently?

I would actually broaden that question. It’s not just drilling contractors but all of our upstream service providers, which is not just drilling and completions but all the services we use in the field. We’re pretty intentional in calling them business partners instead of service providers.

And what a difference two words can make – service provider vs business partner, and that’s indeed how we feel. Let’s be real: They’re the ones that make it happen in the field. They’re the ones that are out there doing the work

For us, the win-win really comes from three things: scale, stability and alignment. EQT can bring the large-scale development. We have a visible, stable and multiyear development schedule. This schedule feeds our development plan, it feeds our capital allocation, and it feeds reserves. I don’t know if other operators can say the same thing, but that lets our partners increase utilization of their people and their equipment.

In return, we benefit from lower costs and better performance, because they can justify investing in technology, training and continuous improvement around our longer-term program.

Looking at the wells being drilled in the industry today, do you think we’re getting as much out of them as we can? If not, what technologies do you think can help us improve that?

As engineers and scientists, we are never satisfied. We always want more from our wells. There are two big levers to achieving well performance gains: improving recovery factors and improving uptime. With recovery, modern stimulation techniques have allowed us to recover about half of the gas in place in the past 50 years. That means there’s another half that’s still there. We’re leaving a lot of gas in the ground.

The question is, how do we increase that recovery factor, or pull the recovery factor up in as short amount of time as possible?

There are new downhole diagnostics that are going to be critical tools that really let us understand what we call our stimulated rock volume, or SRV, and how fractures are growing, how the parent/child and offset interactions are playing out, and how that might impact our well designs. If we can have better subsurface insight, it will allow us to tailor spacing, completion designs and even redevelopment strategies so that each dollar of capital recovers more molecules.

The second lever for us is uptime, or how often your well is flowing. You start with whether the flow meter’s spinning or not. You always want the meter spinning when you’re flowing your wells. For us, nearly all of our producing wells are in a very mountainous region over three states, so checking flow requires improved telemetry so that we can read our wells in real time out in the mountains.

We also leverage edge devices to do this. Having real-time SCADA systems allows us to avoid significant delays, so we can get that real-time analysis and real-time changes, vs minute, hour or daily delays. Modern predictive models will allow us to operate more remotely and anticipate equipment issues before they turn into downtime events, but we are not there yet.

This is an area of AI we’re exploring. AI is in its infancy, and we’re trying to understand new ways to apply it to improve that uptime. If I know that three weeks out, this well is going to go down on liquid loading, or the tubing is getting a little thin on this well, or we’re going to have a hole in tubing, I can get a work order going, materials ordered and a workover rig ready before that well ever goes down. That’s one of the goals.

As you go through the journey of figuring out where AI fits in the oilfield, what particular areas of interest do you hope to address?

We see AI as a force multiplier for our engineers and scientists, not a replacement for them. I think the real value is in faster, more data-driven, predictive decision making. The way we think about AI right now is, rather than boiling the ocean, we’re breaking it down to the simple, repetitive things. Where can AI do the housekeeping for us? We don’t want to do laundry and we don’t want to do dishes; we’d rather paint or garden. So how can we have AI do the dishes and the laundry for us?

To bring these analogies to the oilfield, how can we monitor thousands of wells, thousands of compressors, all the different pieces of equipment, and look for that one thing that’s going to drift outside of normal?

We want AI to be constantly watching, so when the dishes are starting to get dirty, it gives us a timely warning and makes suggestions on what to do about it. Then our people can step in and make the decision on how to act, using smart engineering judgment. There could be different AI models that optimize parameters in real time to minimize vibration, stick-slip, bit trips or rate of penetration. We’re not there yet, but those are some examples.

For completions, obviously we’re looking at pattern recognition across thousands of stages. That’s not only the pressures and rates of treating the stages, but some of the real-time information that we receive from the geosteering tool can tell us about the rock so they can recommend pump schedules or fluid systems or problem zones. Those are some topics we’re trying to leverage AI for in completions, but they are still in their infancy.

In all of these cases, AI is just surfacing issues earlier, laying out some of the options, and then our teams of engineers and scientists can choose the path that best balances safety, reliability and economics. We are just at the beginning of figuring that out, and the team is digging into what it will take to truly become agentic.

Lateral lengths are continuing to grow in several unconventional basins, with 3- and 4-mile laterals quickly becoming the norm. What is your view on this trend? Do you think the industry will continue finding ways to lengthen its wells?

I think we will go farther. What limits us right now is the rig and the frac technology. As long as the rig and technology are high performing, we’ll continue to drill longer. It’s the same on the frac side: The longer the laterals are, the more purposeful you have to be on how you design the toe of the frac to get a good frac-off and a good stimulation.

The equipment that you have on the surface – whether it’s 10,000-psi equipment, or the 15,000-psi equipment we’re pumping now, or the 25,000-psi equipment we’ll eventually need in the future – we’ll continue to improve the technology so that we can reach those long laterals.

Going longer in the same wellbore always improves cost per foot because you spread those costs of the pad, the surface location, the road construction and the vertical section – the one-time costs, more or less – over more productive footage. You’re preventing waste and minimizing surface impact while also efficiently developing the reservoir. As long as you can safely drill, complete and produce those really long laterals, and the regulatory framework around drill and spacing units evolves with the technology, that trend is going to continue.

On the drilling side, as the rigs continue to improve with their technologies, the faster and more responsive our directional and geosteering tools can be, the better real-time data we get for in zone. We want to stay “in zone” over those miles, leveraging smart geosteering techniques.

On the completion side, we’re going to need higher pressure-rated equipment, and we’ll need to improve our materials to manage frictional pressure losses. Frictional pressure is the enemy in fracking. Developing fluid technology that allows you to minimize friction so that you can maximize pressure down there will be another huge component. DC