Good morning, and thanks for joining us. I'm Linda Cook, the CEO of Harbour Energy. Alexander Krane is here with me, our CFO, and we're looking forward to running through our results and then taking your questions. I'd like to first start by acknowledging the challenge that high energy prices are presenting to many people. Of course, one way to address high prices is to increase supply. As an oil and gas company, that's what we're focused on, doing what we can to deliver reliable domestic supply in a safe and responsible manner. I think you'll see examples of this as we go through the presentation. If we could start on page three, please. Overall, we're pleased with the company's performance through the first six months of this year. This includes across our operations, where we delivered improvements with respect to safety, emissions, and reliability.
Production was up materially over last year, and unit operating costs were down. As a result of this, and some help from the higher commodity price environment, financial results were robust. We generated free cash flow of $1.4 billion and continued to rapidly deleverage with net debt of $1.1 billion at mid-year, down 50% since year-end and down from the $2.9 billion we had at completion of the Premier merger less than 18 months ago. This leaves us in a very strong financial position, supporting our decision to increase the current buyback program to $300 million, giving us total distributions to shareholders of $500 million during the calendar year, while leaving us with flexibility over future capital allocation.
Turning to page five, I'll cover some highlights from our operational performance, and then after that, I'll turn it over to Alexander, who will dive into the financials. As I already mentioned, safety performance was generally improved. Incident rates were lower, with no significant injuries or spills during the period, which included several fairly intensive offshore installation maintenance shutdowns. However, we're not fully satisfied and never will be. We investigate every incident and near miss, and we share the learnings across the company. We'll hold our second Global Safety Day in just a few weeks, focusing this year on back to basics and strengthening our process safety culture. On the next page, we show some history and an overview of our portfolio today.
Harbour was formed just a few years ago and has grown from zero to more than 200,000 barrels per day in a short period of time by acquiring assets from large companies and then reinvesting in them to improve efficiency, add reserves, and extend producing life. All of these activities are important to supporting domestic energy security. Today, we account for about 15% of U.K. domestic oil and gas supply, with over 90% of our production coming from the country. Within our U.K. portfolio, however, we do have significant diversity. Production is about 50/50 oil versus gas in a split over 10 different hubs, with no single hub contributing more than 20%. We operate a majority of our assets, which enables us to drive efficiency and control the pace of investment. With average operating costs of about $15 per barrel, margins are strong.
This leads to material cash flow generation that supports both continued investment in high return projects and the capacity for shareholder returns. Page seven, please. I'm proud of the team's operational delivery during the period. As I mentioned earlier, production is up materially by 40% over last year. Yes, some of this was the result of the acquisition of Premier, but we had similar material contributions from improved reliability and new wells. Excluding the Premier acquisition, production was still up materially by 17% versus last year. In the upper right, you can see the improvement in production efficiency, which reflects in part the large amount of planned maintenance last year. Those shutdowns allowed us to complete a lot of non-safety critical maintenance that had been deferred from 2020 due to COVID, and this is now supporting our high reliability.
With the ramp-up of drilling activity in the latter part of last year, we benefited this year from the contribution of a number of new wells coming on stream. This includes, of course, at Tolmount. The project started up in April and was fully ramped up by early June. It has since been producing consistently at or above our target rate of 20,000 barrels per day net to Harbour. On a gross basis, Tolmount is now accounting for more than 5% of U.K. domestic gas supply. Looking to the second half, production in July and August is impacted by planned maintenance, including at Beryl, J-Area, and Catcher, almost all of which is now behind us.
Our first half production of 211,000 barrels per day, together with the startup of Tolmount and the near completion of the summer maintenance campaigns, reduces the risk around our full year forecast, enabling us to narrow guidance today to 200-210,000 barrels per day. Let's turn next to our investment program. In line with our strategy, most of our money is being spent on short cycle, low risk, infill or near field development and appraisal wells. In addition to our fairly steady stream of U.K. decommissioning activity. As you can see from the rig schedule, we're a lot busier in the second half of the year than the first, and this is largely as planned, although we did see material delays in the arrival of two rigs in the first half of the year.
This means our CapEx spending will be higher in the last six months than in the first. Overall spending is now estimated to be about $100 million lower than originally anticipated, but still up 30% over last year. Alexander will talk more about all of this later. On page nine, we show some of the highlights of our organic portfolio, starting with the U.K. on the top part of the page. At J area, following the successful appraisal well drilled last year, we recently approved the development of the Talbot Oil Field with a Harbour interest of 67%. The project includes the drilling of three wells to be completed as sub-sea tiebacks to our Judy platform. Our partner, Eni, has also approved the project, and we're now waiting on final regulatory approval, following which drilling should commence, hopefully by year-end.
This is a good example of moving volumes from our 2C contingent resources into 2P. We acquired our interest in the Talbot discovery through our ConocoPhillips transaction in 2019. Seeing the potential to develop it through a tieback to our Judy platform, we drilled the appraisal well in 2021 in order to de-risk the development and have now approved the project. If all goes according to plan, first production should occur around the end of 2024. Talbot is also a good example of collaboration with other operators. We designed the project to accommodate production from the redevelopment of NEO Energy's nearby Affleck field. This reduces emissions and improves the economics for both companies, realizing cost efficiencies from sharing a rig, as well as in the project construction and execution. Ultimately, we'll also benefit from NEO Energy's third-party volumes coming across our Judy platform.
Elsewhere in the U.K., we sanctioned an appraisal well for the Leverett gas discovery expected to be drilled in 2023. This is another good example of sector cooperation as we recently executed an exchange agreement with NEO Energy to equalize interests across the various Leverett licenses. This enables us to jointly appraise the field in an efficient manner while sharing the risk. If ultimately developed, Leverett would be tied back to our Greater Britannia infrastructure. Regarding existing operations at Greater Britannia, we've seen continued outperformance from our Callanish and Broguer satellite fields and have plans to return to drilling at Callanish in 2023. Internationally, we continue with the technical design work for the development of the Tuna discovery in Indonesia, aiming to enter the FEED phase next year.
Similarly, at Zama in Mexico, there's now good momentum working with Pemex to progress the development design with the possibility of an FID by the end of next year. Southwest of Zama on Block 30, where we acquired an interest from our Premier acquisition, we'll participate in the drilling of two exploration commitment wells in the coming months, both operated by Wintershall Dea. Finally, we had a discovery at our Timpan exploration well, and I have more about that on the next page. The Timpan Well is located on one of three licenses in which we hold an interest in the Andaman Sea, offshore North Sumatra in Indonesia. Drilled by Harbour on the Andaman Two license with partners BP and Mubadala, the well was drilled in 4,200 feet of water to a total depth of almost 14,000 feet, safely and under budget.
While there is a lot of work ahead to analyze the extensive data set acquired, the good news is that gas was found in large quantities, and this de-risked, to some extent, multiple other multi-TCF prospects across the acreage. On the more cautionary side, permeability was on the low side of expectations, meaning that reservoir quality at that location is not as good as we hoped it might be. What's next? With the support of our partners, we've already approved the acquisition of 3D seismic on the eastern part of the Andaman Two license and are in discussions about the possibility of drilling two to three wells, exploration and/or appraisal, perhaps starting late next year and carrying on into 2024.
Another component of our strategy is to continue growing and to diversify through M&A, aiming to establish a material base of production in at least one region outside the U.K.. While the high and volatile commodity prices make it challenging to establish fair value, there's no shortage of opportunities to consider. Majors selling assets, small companies looking to merge, and private companies looking for an exit. What do we screen for? Our focus remains largely unchanged. Material producing assets with positive cash flow that are accretive to our reserves life, operating margins, and greenhouse gas emissions intensity. We, of course, also remain very focused on value as we have in the past, with M&A needing to compete for capital with organic investments, safeguarding the balance sheet, and shareholder returns. In the lower part of the slide, you can see a bit of our track record in this area.
On the left, we show the reserves acquired from our Shell and ConocoPhillips acquisitions in 2017 and 2019, respectively. At the end of 2021, the sum of cumulative production since then and reserves at that time showed an increase of 30%, demonstrating that we added over 150 million barrels of oil equivalent during that period, mainly through our reinvestment activity and improvements in operating efficiency. In the middle, you see progress regarding costs. Estimates of the cost to decommission the U.K. assets acquired from both Shell and ConocoPhillips is now $500 million lower than the estimate at the time of acquisition. Today's operating costs are also lower by $1 per barrel than originally projected. In both cases, these things add material value to the acquisitions.
Finally, on the right, you see we've been able to execute three multibillion-dollar acquisitions, Shell, Conoco, and Premier in the last five years. By hedging to protect us from periods of low oil prices, as we had in 2020, we've been able to lock in returns while protecting the balance sheet and are now projected to be net debt-free in just a few months' time. I mentioned one of our M&A criteria was emissions intensity. That's in support of our aim to continue to improve the environmental performance of our portfolio. So far this year, we've lowered greenhouse gas emissions intensity by 13% versus the first half of last year. Absolute emissions are, however, forecast to be up slightly due to the increase in production, drilling, and decommissioning activity.
The intensity improvements are the result of a wide range of actions, almost all NPV positive, since they also deliver improved uptime and/or lower fuel usage. In terms of the U.K. government's ambitions, we are well-positioned to help, not just through reducing the environmental impact of our own emissions, but also by utilizing our skills and idle infrastructure to deliver the country's CCS goals, where they're aiming to capture and store underground 20-30 million tons per annum of industrial CO2 by 2030. We're involved in two projects, Acorn in Scotland and the Harbour-operated V Net Zero project in the Humber region. Both will apply under Track-2 of the government sequencing process, which we're hoping will be launched before the end of this year. In the meantime, we're continuing to make progress.
At V Net Zero, we already secured the offshore storage licenses at the Viking field, which is already connected to shore by an existing and now idle gas pipeline. We've now commenced preparations for consultations with landowners along the onshore pipeline right-of-way that will provide the connection to industrial emitters in the area. This CCS project alone could deliver more than one-third of the government's CCS goal by 2030. Should we be selected to proceed under the Track-2 process, we could enter the FEED stage as early as next year. Okay, I'm gonna stop there on operations and turn it over to Alexander to discuss the financials.
All right. Thank you, Linda, and good morning to everyone listening in. I am pleased to share with you today what is our first set of results to reflect the full contribution of the Premier portfolio since the acquisition completed in March last year. I'll start here with the half-year financial highlights. I will then cover the income statement and balance sheet as usual, followed by cash flow and net debt. I will talk about how our past hedging strategy has impacted and will continue to impact revenues going forward and how we are slightly tweaking our hedging strategy. I will finish with 2022 guidance. We have delivered a strong set of first half financial results.
This is underpinned by a robust operational performance which saw us significantly increase production and realize higher commodity prices, particularly from our U.K. gas sales compared to the same period last year. This, together with continuing to actively manage our cost base, has contributed to a materially higher EBITDA. We have continued to invest in our high-quality asset base and have remained disciplined, allocating capital to our best projects which meet our corporate investment standards. We have also continued to safely execute our decommissioning plans. We have seen some inflation coming through, but we have been able to manage that, benefiting from our scale. As Linda mentioned, we are the largest producer and investor in the U.K. North Sea today and through the frame agreements that we have in place. We have seen some cost increases in labor rates and raw materials such as fuel and chemicals.
This has been partially offset by the weaker pound sterling to U.S. dollar exchange rates and operational synergies as we complete the integration of past acquisitions and realize efficiencies as a result of collaboration with other North Sea operators. We have rapidly deleveraged during the first six months of the year and reduced our net debt by over 50% to $1.1 billion at the end of the period. This strengthened financial position, together with good cash flow, has enabled us today to announce a 50% increase in our buyback program to $300 million. Turning to the income statement. As I mentioned at the start, this is our first full set of results since the Chrysaor-Premier merger. This means that the income statement last year reflected six months of Chrysaor activity and only three months of Premier activity.
Whereas this year, we are accounting for a full six months of the enlarged group. As mentioned by Linda, production was 211,000 barrels of oil equivalents per day versus 151,000 in the first half of 2021. Liquids accounted for 53% and gas 47% of production. Pre-hedging, we realized oil prices of $105 per barrel and U.K. gas prices of 165 pence per therm, broadly in line with the average Brent and NBP prices during the period. On a post-hedge basis, we realized $82 per barrel and 69 pence per therm, reflecting our significant hedging program, particularly on the U.K. gas side, where we have hedged approximately 70% of our full year 2022 U.K. gas production.
For our Indonesia gas sales, we realized the equivalent of $16 per MCF. The 40% production increase together with higher realized prices resulted in a 90% increase in revenues, excluding other income, and this is after accounting for realized hedging losses of $1.6 billion for the first half. Crude sales accounted for almost 60% of our revenues at $1.5 billion, up around 70% on the prior period. Gas sales accounted for $1 billion of our revenues, up almost 150%. While condensate sales were around $100 million, where we continue to realize approximately 60% of Brent prices. Operating costs were higher on an absolute basis at $542 million, reflecting the additional three months of operating costs from the Premier portfolio and the addition of Tolmount, which came on stream during the period.
On a unit of production basis, our OpEx reduced to $14.20 per BOE, driven by materially higher production efficiency and a weaker pound sterling to U.S. dollar exchange rate, with most of Harbour's U.K. operating cost being sterling denominated. The higher revenue and lower operating costs contributed to a significantly higher EBITDA this year of around $2 versus 0.8 billion last year. DD&A expense amounted to $742 million, equivalent to 19.40 per BOE, which was in line with first half of 2021. We did not have any new impairments or reversals of the previous impaired assets, nor did we incur any material exploration write-offs during the period. Spending related to our carbon capture and storage and pre-license costs are expensed within exploration expenses here in the income statement and amounted to $20 million.
G&A amounted to $43 million compared to $59 million in the first half of 2021, which then included $31 million of merger-related costs. Net financing expense amounted to $117 million, in line with the first half in 2021. This includes interest costs of $48 million, bank and commitment fees of 39 million, and accretion expenses related to decom of 32 million. There is a further breakdown of finance items in note six in the financial statements. In addition, you will see that we have split out from other, from our net financing line a significant pre-tax FX gain of $360 million. Now, this is a bit technical, but in short, this is mainly an unrealized FX gain arising from our pound sterling denominated U.K. gas hedges.
Some of these UK gas hedges, which are booked as a liability, sit in U.S. dollar functional currency entities. When the pound sterling weakens against U.S. dollar, this liability, measured in U.S. dollar terms, is smaller, and hence an unrealized gain is booked. The tax expense for first half of 2022 was $506 million. This is split $473 million in the U.K. and $33 million in international, compared to a total of $33 million in the first half last year. We had an effective tax rate of 34% compared to 28% in the first half of 2021. This increase is caused by a higher proportion of profits being generated in the U.K. compared to overseas.
Overall, net profit for the period was close to $1 billion compared to 87 million last year, with earnings per share at $1.10 versus point one for the prior period. Again, the unrealized FX gain impacts the EPS quite significantly. If we adjusted for this FX effect, the corresponding net profit and EPS would be around $750 million, and 0.80 per share, respectively. The balance sheet shows total assets have increased from $14.5 to 15.3 billion. The most significant increase from year-end 2021 is within the deferred tax asset balance. This comes mainly as a result of higher unrealized hedging liabilities. Goodwill and intangible assets are unchanged, while PP&E are down around $600 million, as the E&A expense was higher than capital investment in the period.
Cash balances were slightly higher on 30 June at $845 versus 700 million at the end of last year. On the liability side, the first thing to notice is probably the equity deficit of around $800 million. This is due to the unrealized post-tax position of the derivative liabilities, which will reverse and crystallize against future revenue from the corresponding hedge production. Most of these hedges will be realized in 2022 and 2023, as I will show on slide 20. Borrowings of $1.9 billion, which consist mainly of our reserve-based lending, or RBL facility, and bond showed a significant reduction due to RBL repayments of $1 billion.
Provisions for decommissioning liabilities of $5.1 billion decreased in the period by around $250 million, mainly due to favorable FX movements and actual decom spending in the period. Now again, as a reminder, this will unwind over the next decades, and we estimate around $300 million pre-tax in spending per year in the medium term. Lease liabilities increased to $0.9 from 0.7 billion from the recognition of certain leased Tolmount topside assets following first gas from that field in April. Derivative liabilities from hedging activities increased to $6.9 billion on June 30, 2022, from $3.9 billion at year-end. The associated deferred tax asset is included in total assets, as previously noted.
Other liabilities of $1.2 billion comprises of trade creditors and other payables of $0.9 billion, and current tax and other provisions of $0.3 billion. Let us move to slides 18 and have a look at cash flow. Here we are illustrating the significant gross operating cash flow we generated during the period, and how this supports continued investment in our asset base, shareholder returns, and a rapid debt paydown. Investments on capital expenditure and decommissioning amounted to $0.4 billion, of which $0.3 billion was allocated to P&E and E&A, and $0.1 billion to decommissioning. Over 80% of our total CapEx in the first half was in the U.K.. Financing cash flow consists of bank interest and fees and lease payments for a total of $0.2 billion. Tax paid was $0.2 billion as well.
Again, most of this was in the U.K.. As a reminder, tax in the U.K. is paid in three installments in July, October, and January in the following year. During the first half, we also paid out a $98 million dividend in May, and we also repurchased shares for around $54 million. As a result, we generated $1.4 billion of free cash flow after tax and before distributions during this period. This resulted in our net debt reducing to $1.1 billion at the end of June. This strong financial performance, which is underpinned by a high quality and diverse asset base, supports our $200 million per annum dividend program, and it also enables us today to increase the $200 share buyback to 300 million, a program we initiated less than two months ago.
This brings our total planned shareholder distributions for 2022 to $500 million, which we believe is meaningful and competitive. We will continue to regularly review our shareholder returns policy within the context of our prudent and disciplined approach to capital allocation. The annual redetermination of the RBL took place on June 30, and we decided to bring forward by six months the scheduled $400 million amortization at year-end. This means that the RBL facility now stands at $4.1 billion. The new borrowing base is $2.7 billion, and the letters of credit sublimit is $1.5 billion. Collectively, more than the facility amount. No redetermination or amortization to take place until June 30, 2023.
As at period end, we had significant liquidity of some $2.2 billion, comprising undrawn capacity on the RBL of $1.4 billion, and cash of 0.8 billion. As part of the redetermination, we also secured greater flexibility around our hedging program going forward, and we will get to that in a minute or two. In March this year, at our full year results presentation, we provided a free cash flow sensitivity at average full year 2022 commodity prices of $100 per barrel and 200 pence per therm of $1.7- 1.9 billion after tax, but before distributions.
We've updated that free cash flow sensitivity to take into account our strong operational performance during the first half of the year, including the subsequent narrowing upwards of our production guidance, together with a lower $100 million full year CapEx forecast. This more than offsets the expected impact of the EPL on our 2022 free cash flow. As a result, we've increased our 2022 free cash flow sensitivity to $1.8-2 billion, reflecting forecast free cash flow of around $0.5 billion in the second half. This is lower than in the first half, reflecting the phasing with over $1 billion of CapEx and tax payments scheduled for the second half compared to 0.5 billion in the first half. We continue to forecast to be net debt-free in 2023 at $100 per barrel and 200 pence per therm.
The EPL reduces our sensitivity to commodity prices. Our sensitivity to oil prices has reduced with a $10 per barrel change in the full year 2022 Brent price now resulting in a $120 million change. Our sensitivity to U.K. gas prices has, however, increased slightly, with a 0.20 pence per therm change in U.K. gas prices resulting in a $110 million change in free cash flow. The Energy Profits Levy was enacted in the U.K. in July and applies an additional tax on profits from U.K. production from May 26, 2022. We expect our EPL liability for the fiscal year 2022 to be in the order of $300 million, with around a $170 million to be paid in December 2022, and the balance in early 2023.
Now, historically, the starting point for our hedging policy has been the minimum and the maximum hedging requirements set out in our bank facility. While this remains true today, with our leverage now well below one times, we are looking to increase our exposure to market pricing. You can see the hedged volumes and pricing on the left-hand side here. A lot of the historical hedges were put in place to comply with minimum hedging requirements of 50%, 40%, and 30% respectively for years one, two, and three. Last year, we removed the RBL minimum hedging requirement for year three. Now, following the latest June 30 redetermination of the RBL facility, we have reduced the RBL minimum hedging requirements even further.
Specifically, we have reduced the year one and year two requirements by 10 percentage points, so the minimum requirements now sit at 40% and 30%, which gives us more flexibility to take advantage of upsides from any strengthening of the curve while still protecting future free cash flow and shareholder returns through a predictable hedging program. We can all see the volatility in oil and gas markets these days. We are doing our utmost in navigating these waters, ensuring predictability in revenues and protection to the downside, but at the same time trying to retain more of the upside exposure to commodity prices. Historically, we've hedged through selling forward and through swaps. This remains the case for oil, where, and as illustrated towards the right-hand side here, we have been able to secure some attractive prices lately.
However, you will see that for some of the gas hedges we have put in place, we have opted to put in place zero cost collars at quite attractive terms. At current levels, we're able to protect revenues down to levels around 150 pence per therm while preserving significant upside exposure. The ceiling or cap is set at increasingly higher levels from around 300 pence now up to significantly higher levels than this. We will continue to seek to put in place some longer-dated hedging where pricing is attractive, locking in material free cash flow. In my last slide, we have summarized our guidance for 2022. Free cash flow has been very strong in the first half of the year.
While we expect the second half of the year to be impacted by heavier CapEx spend, more tax payments, and of course the $100 million dividend payment and the upsized buyback program. As mentioned, we are narrowing our production guidance for the year to 200-210 thousand BOE per day. On OpEx, we still expect to end up in the $15-16 range, although we do see the risk skewed to the lower end of this range right now. On CapEx and decom spend, we recognize that we are somewhat behind estimated spending on June 30. However, we expect to catch up quite a bit in the second half of the year.
Still, some spending is likely to move into the early parts of 2023, and we are, as a result, revising guidance down by $100 million to 1.2 billion for 2022 total spending. With that, I will turn it back to Linda for some concluding remarks.
Thanks, Alexander. I hope this has given everyone some insight into our performance for the first half. I think we saw improvement in a number of areas and delivered a solid set of financials. As I said earlier, ending the period in a very strong financial position, which enabled us to announce the expansion of our buyback program while retaining the ability to execute the strategy over time and to consider the potential for additional shareholder returns. Thanks for listening to all of this, and we're now happy to take your questions.
To ask a question, please press star followed by one on your telephone keypad now. We will now go to our first question, which is from Nathan Piper with Investec. Nathan, please go ahead.
Morning. Morning, everyone. Thanks for the presentation. I've got three quick questions, please. First of all, on the longevity of the U.K. production base, you've obviously had a strong first half, drilling lots of wells in the second half. How long do you think you can sustain approximately this rate of production? And do you expect to do more than replace your 2P reserves as you develop your U.K. asset base? Second one is, what's the kind of timescale that you see on M&A? So I guess what I'm thinking is you've laid out the landscape, but how long can you continue with what looks to be a significant amount of cash on your balance sheet without materially increasing shareholder returns if you're unable to do a deal?
What's the kind of no-deal situation? How long would you maintain a very, very strong financial position? And then the last one, are there more details on what the carbon capture and storage business model might look like in the U.K.? Obviously the need is there, but I guess, the financial metrics and the rates of return are still to be finalized. Some detail on those, please, would be very helpful. Thank you.
Okay. Thanks, Nathan. We're having a little bit of trouble trying to hear, but I think I caught the three questions, and I'll try to address them all. The first was around the longevity of our U.K. production base, and how long we can keep production flat, replacing reserves, et cetera. I think if you recall, our 2P R/P may have been around 6.7 at the end of last year. Our forecast that we presented at Capital Markets Day late last year showed that we'd be able to keep production relatively flattish for a three-year period. That's still the case today, so we're not changing that guidance. With respect to the longer term, I mean, we've done a good job over the past few years being able to replace reserves and keep production relatively flat.
We're having good performance this year. I think it's hard to say precisely how long we'll be able to keep doing that. Inevitably, of course, the portfolio will see decline, and that's, you know, behind our strategy, which is to continue to execute M&A over time in order to continue to grow. That remains the case today. That brings us to the M&A question, which actually I think was more around shareholder returns. Yeah, you're right. If we don't execute M&A, well, let's start with production and development CapEx, exploration. We've always said we sort of like the level that we're spending at this year, around the $1.2 billion mark. We think that's the right pace of investment for the portfolio we have today.
If we continue to delever and generate the kinds of cash like we are this year, then the options above and beyond that are either for shareholder returns, or M&A, and we continue to assess those options, you know, every single day and week and month. We discuss them at every single board meeting. I think as you saw today, given where we are today, decided the right thing to do was to expand the buyback program. We'll just continue to assess all of those options on a regular basis going forward. The CCS business model. Yeah, I wish I had a really good answer for you.
I think, in the U.K. at least, until we get more clarity from the government, through their Track-1 and Track-2 processes around the commercial and regulatory framework, it's a little bit hard to be precise around the business model. What we do know is that we have the skills and the capability and some existing infrastructure that can really help lower the cost of CCS in the country, and our V Net Zero project is a good example of that. Our focus, I think, largely will remain on the transportation and storage part of that value chain. That's where we have the expertise. You know, we always know how to develop and operate pipelines. The same thing with drilling wells offshore, injecting fluids. For V Net Zero, we already understand the details of the Viking fields, which is where we're gonna store the CO2.
That, I think, puts us, you know, a big step ahead on that project with respect to some others. Our focus is on that part of the value chain. That's where we have the knowledge and skills and bits of kit that can be deployed and exactly what the business model will be, I think, depends a lot on getting some further clarity from the government.
Our next question today comes from Matt Smith with Bank of America. Please go ahead, Matt.
Yeah, morning. Thanks very much for the presentation. A couple of questions. First, picking up on the interesting comment, I think, around your gas sensitivity in relation to your free cash flow for this year actually moving higher despite the fact that we've got the windfall tax to now account for. Does that suggest that your U.K. gas production is performing ahead of expectations? I wondered if you could perhaps give us a bit more color on that. Perhaps that's linked to Tolmount. And perhaps even if you could talk to the evolution of how that sensitivity might be somewhat second half-weighted this year compared to the first. And the second question would be around shareholder returns. Obviously a very welcome announcement on the buyback today.
I just wonder, based on the run rates, how quickly you've been able to execute on the $200 million already announced, and the language that I think you've used in the press release, it seems to me to open the door for perhaps further buybacks to be announced before full year results. Just wanted to see if you sort of agree to that characterization and also just if we could link that question to how you weigh up your distributions, whether they're going to come back via buybacks or dividends, that'd be very useful. Thanks.
Thanks, Matt. Let me start with the first one. I think your suspicion there is right. We're slightly more gas-heavy towards the second half of the year compared to the first half of the year. I think we had, you know, realized prices at around 175p or something in the first half. Yes, slightly more gas-heavy in the second half, which adds to the sensitivity on that question.
In terms of buybacks, yeah, you know, as you've seen from some of the slides here and narrative, we are obviously spending, you know, significantly more on CapEx, there's more on tax here in the U.K., and there's, you know, both buybacks and dividends happening now. Clearly, free cash flow is significantly better in the first half of the year. I think we're today around 85% through the initial $200 million buyback program. It's, you know, adding to this and continuing to buy back shares on a, you know, same pace, seems like a, you know, both prudent and sensible thing to do.
We think just the quality of the results, the performance so far, you know, it feels good to you know, be adding to that buyback program. It's $100 million now that's you know, that's meaningful. That's 50% increase. You know, you should just expect us you know, with the board to just regularly assess this going forward and weigh all the options you know, of capital allocation and you know, potential further shareholder distribution there.
All right. Thanks. Can I just follow up sort of how you sort of frame the debate on the buyback versus the dividend, when you think about any further increases going forward?
I'm so sorry, Matt. I'm gonna ask you to repeat that.
Well, I think I got it. It was how, Alexander, how do we think about dividends versus buybacks? I mean, when we first announced our dividend, you know, we talked about wanting to have one that we felt was affordable, and that we would be able to sustain through the cycle. We set it at the level we did at $200 million a year. Since that time, we've had higher prices than we've expected, and we've been de-levering faster than we thought we would. That enabled us to initiate the buyback program a few months ago. We said at the time we'd continue to assess the situation as time went on. So we've done that, and what's happened since then, prices have remained high.
We've paid down more debt, or our net debt is lower than we had anticipated. At the same time, there's as much uncertainty, if not more, in the fiscal, economic, and geopolitical environment than there was three months ago. We felt like we had the opportunity to do more at this point in time, but given all of that uncertainty, it's, I think, a little bit difficult to think about doing anything with the dividend. The easier call for us was to expand the buyback program at this point in time. That sort of gives you some insight into the thinking. It's really around longevity, uncertainty, and volatility in how we see future cash flows and the general business environment.
Perfect. Thanks very much. I'll hand it over.
Our next question comes from James Hosie with Barclays. Please go ahead, James.
Hi. Good morning. Thank you for your time. I got a couple of questions. Just first, the acquisition plans. Are you anticipating or planning for reduced access to debt capital in any future transactions? I'm just wondering if that's why you may be happy to sit with a large cash balance while you wait for the right deal. Just slightly differently, just wondered if you could talk a little bit about the project economics for Talbot. I'm just wondering what the breakeven is for the project and whether service cost inflation or capacity issues have been a concern for this project.
Hey, James. I'll let Alexander take the first one, and then I'll say a few words about Talbot.
Yeah, great. No, thanks, James. Yeah, for your first question, yes, well, you will have seen the voluntary early amortization we decided to do on the RBL, so bringing that down from $4.5 to 4.1, and that is just purely you know us trying to manage this and you know avoiding to pay you know fees where we don't need to pay fees. We do still perceive that we have a supporting group of banks with us. That isn't a main concern for us. The cash that....
The rather, you know, significant cash balance that you are seeing, showing up here, we do, of course, try to manage cash as tightly as possible, but the nature of the financial settlement of hedges versus the cash income from, you know, when the physical sales of hydrocarbons takes place, that naturally leaves us with a, you know, rather significant cash balance at the end of the month to settle financial hedges very early on in the month, so typically around day five in the month. Then it's, you know, 10 to 12 days until we get the physical revenue from sales. So yes, it shows up as, you know, rather significant. It isn't an intent there to, you know, be cash heavy just because we're concerned about debt access.
It is purely just timing of payments that results in these cash balances. I'll let Linda talk just a bit about Talbot's breakevens.
Yeah. Great. Thanks, Alexander. The Talbot project, we don't kind of give out individual project costs necessarily, today. You know, think about it as three wells drilled that are then subsea tiebacks to the Judy platform, it'd give you a rough idea. I think it's easy for us to say that project met all of our internal financial criteria for investments, and one of those is the project should break even at an oil price under $35 per barrel. It cleared that hurdle and comfortably passed other hurdles that we have. Inflation in general on capital projects, we're not seeing a whole lot this year, mostly because we had already locked in the cost for our drilling rigs and a lot of other things.
We're not seeing some of the material increases you hear about in the market, although I have to say, when we're starting to look at and take bids for rigs and things for later next year or the following year, we are seeing, you know, some pretty hefty increases in some cases. I think the other thing we struggle with, of course, is lead times for some special equipment, anything with chips in them, for example, corrosion-resistant alloys, certain tubulars. Not unlike, I think, what others are probably seeing in the industry.
Okay, thank you. Could you just be clear what's the reserves associated with Talbot for you?
Yeah. We haven't disclosed individual project reserves, James. Project has always been in our forecast for both CapEx and production.
Thank you.
Our next question comes from Werner Riding with Peel Hunt. Please go ahead.
Yeah. Good morning, everyone. Yeah, in the presentation, some pretty good detail on your near-term work programs, but I was wondering if you could also outline i ncremental projects beyond your current base case program that you've identified that could be accelerated in 2023, 2024, that might not have been progressed were it not for the increase in investment allowance in the U.K.?
Thanks. You know, that's a common question I get is, what additional projects are you able to do because of the EPL? Honestly, I scratch my head a bit about that because, yes, there is an additional allowance that we get. It marginally helps the economics of some projects. The bigger impact is that we have hundreds of millions of dollars less to spend every year because our taxes are higher. You know, in general, when we look at the impact of the EPL, we have less money to invest. It might marginally help the economics of some projects. The other point is, and you'll be aware of this. For us to undertake a drilling program or develop a project, it takes months, if not years, of planning.
First you're drilling exploration wells, then you're running seismic, then you're doing the engineering design work, then you're sending things out for bid, then you have to secure a rig, then you have to order all the long lead equipment. Doing a lot of those things in today's environment is harder and takes longer than it ever has before. The notion that all of a sudden, because the investment allowance is a bit more attractive, we can do a lot more work next year in 2023, you know, is a little bit unreasonable. Most of our rigs for next year are already locked in, so it's just very difficult to make a change in the investment plans that quickly.
All right. Got it. Thank you. I guess perhaps just a final brief one, on hedging again, for Alex. We've seen other E&Ps post pretty significant cash security to give counterparties comfort over their positions. Perhaps you don't need to, but could you quantify the amount of security you guys have needed to lodge for your hedge book?
Yeah, it's zero.
Okay.
Yeah, I mean, it's the hedges we're doing. It's with the counterparties that have the secured RBL in place. There's no margin calls or things like that that I know others are sadly struggling with.
Okay. All right. Thanks.
Our next question comes from Sasikanth Chilukuru with Morgan Stanley. Please go ahead.
Hi. Thanks for taking my questions. I have two left please. The first one, I suppose you had kind of partially answered in the previous question. I just wanted to get your thoughts on the U.K. portfolio following the implementation of the EPL. I wanted to understand how this affects the company's longer-term strategy in the U.K. Would this essentially lead to an increase in the investment levels over in the medium term? Not necessarily immediately, but accelerating perhaps the development of CCS projects or more of the tapping the contingent resource base? Or does this imply more urgency in the need to diversify the production base in different areas? Just wanted to see how this has kind of affected the strategy.
The second question was related to the Timpan discovery. I recognize the point on the need for further exploratory and appraisal drilling in 2023, but I was just wondering if you could share some thoughts on the current findings of the discovery and the current probability that you would attach for a commercial development there.
Thanks, Sasikanth Chilukuru. First question was about our long-term strategy in the U.K. and what impact the EPL might have had on that. We already had, I think, a pretty healthy plan for reinvestment in our existing U.K. assets. We laid that out at Capital Markets Day, and we've talked a few times about the spending level of $1.0- 1.3 billion feeling about right for that existing portfolio, and I think that remains generally unchanged. We have high return projects in that portfolio. We're developing them at a regular pace, aiming to keep a pretty steady drilling profile. I don't necessarily see us increasing or decreasing investment in our existing portfolio because of the EPL.
Other than the fact that we're gonna have to assess every year, depending on what commodity prices are doing, the cash flow we have available, and running it through our thinking around capital allocation and trying to balance, as we always do, protecting the balance sheet with reinvestment in organic opportunities versus M&A versus shareholder returns. As I said earlier, you know, right now, we do have additional taxes as well, so that impacts cash flow on the other side. CCS projects, the details of the EPL unfortunately do not allow us to take an allowance for investment in CCS. I don't see that the EPL actually has helped the CCS projects accelerate, as written today.
What does it do elsewhere for our strategy at a higher level? We've always had a strategy to want to have a more diverse portfolio than we do today. We've always been uncomfortable with the fact that we have a lot of eggs in the U.K. basket and had the ambition to have and establish a material base of production in at least one other region. That remains the same as it's always been, and I think has just been reinforced by what we've seen in terms of the fiscal actions taken in the U.K. today or recently. Time for just one more question.
Our final question comes from Mark Wilson with Jefferies. Please go ahead, Mark.
Okay, thank you for the clarity. Can't believe I still have some questions, but specifically I'd like to ask on the Tolmount field. Great that it's got two plateau rates. In the guidance for the rest of the year, would we expect Tolmount to be continuing at those plateau rates through second half? And indeed, how long do you think that could continue, well, now you've had it on production for a few months? Thank you.
Hey, Mark. On Tolmount, yeah, we were pleased with the time that it took to get us to ramp up to the plateau at Tolmount. So far it's going, you know, so far so good in terms of the production. I think the outlook today, I mean, we're already almost into September, and so. Yeah, we're not anticipating that to change, I think, in the next few months. We'll of course include updates about that, you know, as we go forward. Then don't forget, we've already sanctioned the drilling of Tolmount East, which I think might start drilling next year, if I remember. Oh, late this year, I've just been told. So that's great.
That will help, you know, help us to sustain production for a longer period of time once we get that on stream. I just realized I forgot to answer the question about Timpan earlier. Sorry about that. I think the question, I couldn't quite hear, but I think it was around potential development schemes, maybe. I mean, it's tempting, of course, to wanna talk about that and get very excited when you have a discovery like this. Just to say, first and foremost, we still do have a lot of work to do. We're fortunate to collect a lot of data during the drilling of this well. We've yet to analyze all that. As I said earlier, we didn't have 3D seismic on the eastern side of the Andaman Two license yet.
We've now approved that along with our partners, and we'll acquire that data, I think, late this year. We're in discussions about what we do next. Until we analyze the data, it's a little bit hard to be precise, but the possibility of drilling, as I said, two to three either exploration and/or an appraisal well, starting in the second half of next year is what's under discussions. Then, of course, we'll have more data and need to analyze that. If we should be fortunate and we continue to find large accumulations of gas, multiple prospects are proven up, and maybe we see reservoir quality improve in other locations, then you really start getting excited.
I think the good thing about that is there are a lot of different options for how you might develop this play, depending on how much you find. We're in a part of the world where the demand for gas continues to grow, where there's a shortage of gas. Gas has to be imported into the region, and there's multiple gas markets that can be accessed either by pipeline or, you know, potentially even LNG exports. So a lot of options, I think, will be at our disposal to assess, should we be that fortunate. I think we're going to leave it at that. Thanks, everyone, for dialing in. Thanks for all the good questions. Of course, let us know if you have anything further. Just contact Elizabeth, and we'll be happy to help. All right. Thank you.