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Slide 4 includes some results from the fourth quarter and full year of 2018. Production last quarter met guidance at 699 million cubic feet equivalent per day while full year production totaled 275.1 Bcfe also within our guidance. With a strong production base and our low-risk vertical drilling program coupled with a robust hedge book, we posted a full year adjusted EBITDA of $504 million.

For 2018, our cash costs were $1.01 per Mcfe, affirming our continuous effort to be a low-cost leader. Over the course of the fourth quarter, we brought online 23 operated vertical wells with an average 24-hour IP rate of 8.3 million cubic equivalents per day. For the full year, we brought online a total of 94 operated vertical wells and 16 operated horizontal wells, all in Pinedale.

In the fourth quarter, we reduced our vertical well cost by another 6% quarter-to-quarter, achieving an average of $3.1 million. This cost reduction is driven by further decreases in cycle times, increases in the performance of our bottom hole assemblies primarily bits and mud motors and by maximizing the benefit of simultaneous operations in our pad development of vertical wells.

We are committed to growing our culture of financial discipline. We exited 2018 running three rigs and plan on continuing that pace of development in 2019. With our borrowing base reaffirmed, total debt reduced and maturities extended through our debt exchange initiated in fourth quarter, we have ensured liquidity and financial flexibility to effectively run our business.

Moving to Slide 5. We have outlined some of the key items we executed throughout 2018, all of which lay the foundation for a healthier Ultra Petroleum that now has positive momentum heading into 2019. Over the course of the year, we solidified a new management team and consolidated our headquarters, divested non-core assets, and reduced our debt by $252 million when including additional follow-on exchanges since year-end.

With respect to liquidity, we worked proactively to improve our financial flexibility by working with our bank group on covenant relief. It gives us some room to manage our business through the current commodity price cycle. As part of that process, we completed our semi-annual redetermination last month and as previously disclosed, we were pleased to receive unanimous support from our bank group in the affirmation of our $1.3 billion borrowing base.

Additionally, in early 2019, we received a favorable opinion from the Fifth Circuit in our make-whole claim litigation that could result in the Company being able to recoup up to $260 million. Our team has been hard at work to execute on each of the items on this list and I'm excited to work with David, Jay and the rest of UPL team to continue to shape the next chapters of our story.

On Slide 6, the strategic objectives for 2019 are an extension of what we started nearly a year ago. We will continue to work toward further strengthening of our balance sheet in the coming year. This priority gives us the ability to pursue the projects with the best returns and work toward generating free cash flow.

Our high-quality Pinedale assets are set to deliver consistent and profitable results particularly when combined with the experience of our teams at Ultra. With an Opal gas price of $2.50 and our current cost structure, we have over 1,200 economic locations within our vertical inventory. And with another 2,800 locations that are technically proven, we are driven to reduce costs so that we can unlock that value for shareholders.

Under current gas price conditions, we are managing our pace of development with three operated rigs. We have a long track record of being able to quickly and effectively adjust activity levels based on gas prices. Recent positive movement in gas prices is very encouraging. If the recovery continues even at a modest incremental improvement in Henry Hub price and/or the Northwest Rockies basis, we are poised to realize significant margin expansion.

With that, I'll now turn the call over to Jay to discuss operations.

Jerald Jay Stratton -- Chief Operating Officer

Thank you, Brad. Turning to Slide 7. I want to take a moment and review the scale and opportunity we have in the Pinedale field. Our 79,000 contiguous acres hold an additional 4,000 drilling locations within the core of our asset providing substantial runway for a low-risk manufacturing style of pad drilling. Our acreage sits in the core of the play with gas moving to the Opal hub that has substantial takeaway capacity to multiple destinations.

Over the last 21 years, the Company has produced approximately 3.5 Tcf of natural gas, 26.5 million barrels of oil and drilled more than 2,200 wells from the Pinedale and Jonah fields.

If you'll turn to Slide 8, we'll cover improvements to our vertical well program over the fourth quarter. We saw a cost increase in the second quarter of the year as the Company began to drill horizontal wells alongside its vertical wells. While advantageous for the horizontal ramp up, incremental cost pressures were imposed on the vertical development program. I'm happy to say that in the fourth quarter of the year, vertical well costs came back in line with previous performance and averaged $3.1 million.

While we are pleased to see costs dropping to $3.1 million per well in the fourth quarter, we continue to look for new ways to further improve our cost and increase margins in our new wells. On the drilling side, moving from 3-casing strings to two in our well design offers the opportunity to save up to $400,000 or roughly 13% of our fourth quarter average well costs.

Though we are in the early stages, we had a successful trial with the 2-string wellbore design and we'll continue to pursue these opportunities where conditions allow. Improving bit technology, mud motor endurance and optimization of our bottom hole assemblies are helping to lower cycle times and reduce the number of trips while drilling.

As an example, over 50% of our whole sections were drilled with one trip during the fourth quarter, that was almost double that of the previous quarter. Advancing our completion optimization initiatives, we have transitioned to an HVFR or high viscosity friction reducer fluid system in 16 of 23 wells in Q4. Almost all frac stages are now pumped with this fluid system saving an average of $15,000 to $20,000 per well and allowing for recycle of flow back water on the pad for future completions. This quarter, we'll be testing the new HVFR fluid with double the viscosity in all frac stages including our deepest Mesaverde stages, resulting in a full transition to a 100% HVFR fluid system. Our team continues to look at every opportunity to reduce vertical well cost with new technology and improved processes to increase margins and development program returns.

On Slide 9, we summarize the performance of the vertical wells during the quarter. The Q4 wells continue to perform in line with our 4 Bcf type curve even with cost trending downward. As an operations team, we focus on creating more value. The three levers we have to pull are well productivity, cycle time and cost. We look for ways to improve overall production, shorten times between expenditures and revenue and reduce the capital required for each well.

Looking at the sensitivities on the right of this slide, you can see that in the current environment of $2.75 realized pricing, our vertical wells continued to generate returns 20% or greater today, meaning there is substantial upside associated with improvements to realized gas price, well performance or cost. We believe the Ultra team knows the Pinedale Anticline better and can execute more efficiently than any other operator in the play today and we demonstrate that by how consistently we can bring in wells at the 4 Bcf cumulative production level. We continue to look for ways to improve the performance of each new well. With a combination of reduced costs from innovative technologies and improved processes, Ultra's goal in 2019 is to expand margins and provide investors with more value with each new well we drill.

Moving to Slide 10, we explain our process to achieve greater understanding of the horizontal development opportunity in Pinedale to extend the resource and create incremental value. During the fourth quarter, we completed an important stage in our 3D Seismic Inversion project to approve our characterization of reservoir quality rock away from well control, enhanced our petrophysical model and began history matching well results to an advanced geo-mechanical model.

Coming into 2019, our plan is to continue executing on a structured plan to finish this stochastic stage of our 3D inversion project, building calibrated simulation models for vertical and horizontal well results in the project area and develop an understanding of the stimulative rock volume and connectivity of hydraulic fractures in our Pinedale geology. The understanding of the performance from both vertical and horizontal well results will guide our forward plan for extending the Pinedale resources with horizontal wells. It's also expected to provide insight that will further improve the vertical completion performance in our Pinedale development program.

In January, we completed one of our three drilled and uncompleted horizontal wells, the Warbonnet 13-13-A-1H in the Lower Lance A1 zone. We have postponed our completion on this well into 2019 in order to finish improvements to the petrophysical model and incorporate understanding from nearby horizontal well performance. More precise stage placement was implemented with the new completion design in approximately 6,100 feet of the wellbore. This plan resulted in a 24-hour IP of 17.5 million cubic feet equivalent per day.

We are encouraged that our work with existing horizontal performance data and advancement of our petrophysical model have improved predictability of productive sand on the flank. With progress in our 3D seismic inversion and advanced reservoir characterization, we're encouraged that these results can be replicated in areas further from the core development and existing well control.

Vertical wells continue to be our primary focus as the results from that program are consistently attractive while we continue to look for ways to unlock incremental value through horizontal development. The relatively low cost of the technical work scope on the horizontal side of our development is derisking potential locations and giving us greater comfort than more capital intensive horizontal wells will produce at levels where they can compete with our vertical wells for capital.

And with that, I'll turn the call over to David.

David Honeyfield -- Chief Financial Officer

Thanks, Jay. On the financial front, our strategy continues to be guided by the disciplined investment of capital in the pursuit of free cash flow. Our base production provides significant cash flows from our operations and is complemented by the investment in our drilling and completion activities.

This cash flow continues to support ongoing operations and other efforts completed by the team in the fourth quarter to advance our business. Important milestones since our last call include the successful debt exchange that Brad mentioned as well as the favorable ruling from the Fifth Circuit Court regarding the make-whole decision. These positive events are all steps toward the Company being on better footing moving into 2019.

Slide 11 reflects our results for the fourth quarter and full year 2018 operating metrics. The 699 million cubic feet equivalent per day translates into 64.3 Bcfe of production for the quarter. Highlights are dominated by the continued overall low cost of operations for this Company. We reflect EBITDA cash cost per Mcfe of $1.08 for the quarter and $1.01 for the full year. Inside this result, our strong performance on LOE costs at $0.30 per Mcfe in the fourth quarter offset by higher production taxes at $0.48 per Mcfe. That as an aside, we're happy to pay higher production taxes as that means our realized physical pricing is higher as well. It's worth noting that the cash G&A per Mcfe result looks a bit odd as we excluded the expense from the debt restructuring as well as the Houston office relocation from the cash G&A line.

DD&A per Mcfe and the interest expense per Mcfe remained relatively flat across the year as there are always some slight variations from period-to- period. The culmination of our total efforts is adjusted EBITDA of $504 million for the full year. What I'm always reminded of when I think about the scale of our operation is the impact that just a small uplift in natural gas price can have across the business when you think about our EBITDA cash cost margin of over 60%.

Moving over to Slide 12, you'll see our updated SEC reserve numbers. Our total proved reserves as of the end of 2018 totaled 3.1 Tcfe, which brought Ultra's before tax PV-10 to $2.4 billion providing strong coverage for our secured lenders. Our PUD bookings are based on a vertical well development program of three operated rigs for three years. The reserve base is comprised of approximately 95% natural gas with about 15% of our forecast revenue stream attributed to oil reserves.

As we look at the capital program for 2018, the total capital invested by the Company was $426 million. Finding and development cost for our reserves came in at an all-in number of $1.74 per Mcfe. Looking specifically at the vertical well program, that number comes down significantly to $1.04 per Mcfe, a very respectable number by any measure.

Slide 13 reflects our total debt. As Brad touched on, one of the major objectives for the Company in 2018 was reducing its debt to allow us to better execute on developing the Pinedale field into the future. Late in the year, we successfully closed on the debt exchange of a majority of our 2022 senior notes and 2025 senior notes for the new second lien notes due in 2024.

The benefit of this transaction was a reduction in the face amount of our debt by $235 million and a meaningful extension of the maturity of the debt stack. The table helps summarized what occurred with the December debt exchange. That transaction exchanged $505 million of our '22 notes and $275 million of our '25 notes for $545 million of new second lien secured notes. We significantly moved out the maturity of the exchanged '22 notes to July 2024 with this transaction.

Under the terms of our second lien indenture, we also negotiated a basket to exchange up to $55 million of additional '22 notes at terms that are on the same or a more favorable basis to the Company for a one-year period. To date, we've exchanged an additional $45 million of '22 notes for $27 million of second lien notes, resulting in a further reduction of debt by approximately $18 million.

The $104 million balance outstanding under the revolving credit facility at year-end is probably higher than what people had expected. The primary reason this amount is at this level was due to the timing of derivative settlements and when cash is received for the corresponding physical sales. Derivatives are settled at the beginning of the production month and physical sales receipts are paid to us approximately 50 days later at the end of the month following production. This created an approximate $60 million working capital requirement over year-end. As of the end of February, our cash balance is approximately $6 million and our balance under the revolver has been reduced to $41 million.

One other item, while it does not show up on this slide, it's worth mentioning again that we were able to close on the amendment to our revolving credit facility in February 2019. The amendment was unanimously supported by our bank group and provides significant flexibility and runway for the execution of the Company's strategy, particularly with the benefit of the expanded leverage covenant. Of importance and worth highlighting before we leave this slide is to call out that as of the end of the year, our consolidated net leverage ratio as defined in our revolving credit facility was 3.95 times.

Now, looking to Slide 14, for a current summary of our hedges. The Company will continue to hedge a portion of its production in order to provide a degree of certainty of cash flows and in attempt to be opportunistic in a strengthening natural gas and Rockies basis market. The Company has a minimum hedging requirement under its revolving credit facility to hedge at least 65% of its forecast proved, developed producing natural gas production for the ensuing 18 months. Management also works to balance the ability to provide upside exposure for the Company as the increase in future commodity price has a meaningful impact on our cash flows on unhedged volumes given our low operating costs.

Since our last call in November, the Company has entered into additional natural gas basis derivatives for the period from April to November 2019 at improved differentials compared to previous disclosures. We've been patient in executing these basis trades and we're seeing a stronger outlook for natural gas basis in the Rockies as storage at the end of the winter is one of the lowest levels in years and we look at some of the underlying tightness in the West that's supportive of the Rockies natural gas market.

Since year-end, we've entered into the required hedges for the second quarter of 2020 in order to protect both our downside and to offer exposure to increased natural gas prices, we have utilized a combination of costless collars and deferred premium put contracts for this period. When factoring in the impact of our hedging program, it's always worth reminding people that it's necessary to take both the NYMEX contract and the Northwest Rockies basis contract into effect and then multiply the per MMBTU price of the derivatives by the Company's average BTU factor of 1.07, to yield the impact of the realized price for the natural gas derivative. This value is then combined with the oil contracts to get the final per Mcfe value of the hedges.

On Slide 15, we provide detailed guidance for the first quarter and for the full year 2019. Our capital investment program is expected to total approximately $320 million to $350 million. The drilling, completion and equipment capital for our operated program is estimated at $275 million to $295 million and participation in wells operated by others is estimated at approximately $27 million to $33 million. Other capital of $18 million to $22 million includes facility, leasehold, seismic and other capitalized costs.

We plan to run three operated rigs dedicated to drilling vertical wells in the core of Pinedale and the capital budgeted for the non-operated interest is based on a one-rig program assumption. We expect to fund these capital expenditures primarily through cash flows from operations and cash on hand as well as availability under our revolving credit facility if necessary.

Ultra's 2019 annual production is expected to range between 240 Bcfe and 250 Bcfe. In the first quarter, the average daily production rate is expected to range between 675 million cubic feet per day and 695 million cubic feet per day. For full year 2019, at the midpoint of our operating cost ranges, we are guiding to $1.13 per Mcfe of EBITDA cash cost.

Finally, for those looking to update their modeling, we are providing a range for cash interest expense, which excludes the PIK interest and the amortization impact of the non-cash premium and deferred financing costs that go along with the debt.

Thank you for your support and interest and I'll turn the call back over to Brad to close out our prepared remarks.

Brad Johnson -- President and Chief Executive Officer

Thank you, David. Ultra's operating fundamentals are rooted in optimizing our base production with emphasis on maximum run times and minimum LOE, each of which translates to stronger operating cash flow. We augment that foundation with investments in our vertical well program, high grading the opportunity set and delivering low risk and consistent flow results.

Financially, our priority is to continue to strengthen the balance sheet and maintain liquidity in order to execute our plans. Ultra is hyper-focused on cost control and efficiency, which are the keys to enhancing value of our vertical inventory. We also believe there is significant upside potential in expanding recoverable resources from Pinedale through horizontal development and we look forward to sharing our progress on this effort throughout 2019.

I would like to thank our team for their tremendous effort and execution this past year. In 2019, our goal and expectations is to carry forward the momentum of last year and deliver even better results this year. At this time, we will open the line for questions.

Questions and Answers:

Operator

Thank you, sir. (Operator Instructions) Our first question comes from Jacob Gomolinski-Ekel of Morgan Stanley. Please go ahead.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Hey, guys. 21.1 net wells, I get to about for Q4 -- I get to about $4.2 million (ph) per well just based on the CapEx number you had provided. I realize there might be some non-op and infrastructure and service in there, but can you just help bridge that gap from the $3.1 million per well you mentioned?

Brad Johnson -- President and Chief Executive Officer

Sure. Yes, this is Brad. So the $3.1 million is the average cost for fourth quarter, the 21.1 net wells. The additional capital does include carry-forward capital from the horizontal program that preceded the fourth quarter as well as some pre-drill investment as we build and prepare the pads for drilling rig for the following year. So the remaining balances is related to the pre-drill capital.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Okay, so then for 2019, you're guiding to $285 million of D&C CapEx and $335 million overall. It looks like the guidance suggests production will decline somewhere around 10%. I think you had previously mentioned maintenance CapEx was on the order of $270 million, so it would just be great to understand if something's changed there or if there's something else going on?

Brad Johnson -- President and Chief Executive Officer

Sure. So, yes, our capital program for '19 is $334 million (ph), a little under $320 million of that is allocated for drilling vertical wells. So we that $320 million of D&C in CapEx and looking forward, we're seeing a couple of percent decline, not quite flat, close to being flat, but a little bit below. What that means is our maintenance capital currently ranges between $325 million to $350 million to keep production flat through the year. The difference really is related to the base decline of volumes where last year we were estimating about 24% as we look forward to '19 that corporate base decline is at 26% that's related to of the volumes coming off of, if you recall a year ago we touched eight rigs, where we had a seven rig program consistent in the first quarter and as we have ramped down that program, we are seeing our corporate base decline inch up to 26%. I will point out the $334 million CapEx budget is based on a $3.1 million well cost for our vertical wells. And as Jay mentioned earlier, we see a good opportunity to reduce those costs throughout the year, when you think about a 10% reduction of wells cost against the overall capital budget, there is an opportunity there for us to come in below that $350 million -- $320 million to $350 million range.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Okay, great. And then just one question on the the make-whole and post-petition interest litigation is did you have a sense of, in terms of your own internal expectations for the quantum that might be coming back to you and the timing of when you expect resolution for that and actual cash to change hands if you think it does?

Brad Johnson -- President and Chief Executive Officer

Sure, obviously, we're very pleased with the ruling that came out of the Fifth Circuit and we consider that a three for three ruling on three important parts the make-whole, the premium and the post-petition interest. Obviously, we're very pleased with that result. I can't comment at this time on timing or proceeds recovered by the Company. It's still a litigation matter. So I can't comment further at this time.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Totally understand. Thanks very much. I appreciate it.

Brad Johnson -- President and Chief Executive Officer

Sure. Thank you.

Operator

Thank you. Our next question comes from Michael Scialla from Stifel. Please go ahead.

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Yeah, hello everybody. Brad, congratulations on your appointment to full time CEO and President. I wanted to ask you about the horizontal well that you completed here recently with that rate, is that good enough to work out economically and is that a well that you would have drilled based on your seismic inversion and reservoir stimulation analysis. I know it's still early in that process, but could you tell if that was really a well that you would have drilled based on the data you have now?

Brad Johnson -- President and Chief Executive Officer

Great question, thanks for the congratulations. I'm going to let Jay handle the horizontal well question.

Jerald Jay Stratton -- Chief Operating Officer

Hi, Michael, this is Jay. Yeah, in regard to your first part of that question, it's still a little early to get a good EUR on that initial IP, but we're encouraged that the productivity of the well matched up with our model that we've derived to justify completing what was the drilled but uncompleted well and it's tying in well so far with the inversion work we're doing and as I mentioned in my remarks, the inversion work is really still ongoing. We've completed the deterministic stage and we're moving on to the stochastic stage but the initial insight we gained is very encouraging in that it ties with a lot of the shale sand volume predictions that we see with some of our blind tests.

So we'll just have to stay tuned for how that helps us gain some insight into targets away from well control, but that's the goal and also, we see some opportunity in our vertical wells as I mentioned for increasing some of our productivity and performance.

Brad Johnson -- President and Chief Executive Officer

And I'll just add to those remarks. On Slide 10, where we share some data about this well. It is well down the Warbonnet area. It is an area of the field that we had early on prioritized as being some of the better areas to target and it's also a well that was drilled in the Lower Lance A1 zone, which is the upper zone in the Lower Lance and that's the zone that we've been drilling some of our better wells in and that zone continues to remain our favorite zone. This well was drilled in that summer. It was a well that we had drilled, but we suspended the completion. As you know, we were winding the horizontal program down, but we were able to incorporate much of the learnings that Jay and his team has been pursuing into the design of this well.

I think the other thing to point out is the completed interval of 6,100 feet is truly more of a one-miler than a two-miler. So getting 18 million a day out of a one-mile well, we're very, very encouraged about that, continuing to firm the resource expansion on the flanks of the field, the productivity of these wells when we target them properly in goods zones and so I think that's going to be an area where we'll continue to focus on as we consider obviously, we're going to be continuing to study through the year and as we look out in the back half of the year, putting plans in place to consider drilling a couple of wells based on the work that Jay's team is doing.

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Very good. You don't have any other 2018 horizontal wells that drilled that could potentially be completed in '19, is that right?

Jerald Jay Stratton -- Chief Operating Officer

We do have two other drilled but uncompleted wells, but with the work we've done to date. Michael, we don't see those as attractive enough to make us want to spend the completion dollars on them at this stage. There's still work to be done in those areas of the field to understand how we could best attack that and to your point earlier that this 13-13 Well, we didn't have a choice of where to land it but I think the inversion work that we're doing and will guide us even further toward optimizing that targeting.

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Great. And then just one more for David. On the balance sheet in the press release it show $228 million of premium on exchange transaction. Can you explain what that is, is that real debt or how should we view that?

David Honeyfield -- Chief Financial Officer

Mike, this is Dave. Thanks for the question. I think that's a very, I mean that's really observant of you and I appreciate you asking it because it does need a little bit of discussion. That is not something that we have a payment obligation on, it's kind of an interesting situation when you go through the accounting literature on the debt exchange and what we see on that is, it really represents the reduction of the principal, but what the accounting rules have you do in that situation based on kind of the technical classification of how the exchange work is hang that up on the balance sheet and the effect it will have, is it will actually cause our overall interest expense on the P&L to be lower than what the stated face amount of principal times debt so -- the principal balance we show that as of the end of, well, we frankly we showed in our slide deck that we're below $2 billion (ph) in total debt as of the end of February.

And that's our, that's how you should think about repayment obligation on that. We've broken that out in pretty good detail on the financials that will get filed in the 10-K here shortly. So it is something to pay attention to. We've tried to call out as brightly as we can just so folks don't accidentally pickup that premium.

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Great. I appreciate it.

Operator

Thank you. (Operator Instructions) Our next question comes from Kevin Kuzio from First Eagle Investment Management. Please go ahead.

Kevin Kuzio -- First Eagle Investment Management -- Analyst

Thank you. I saw that strengthening the balance sheet was listed under both strategic objectives at the beginning and the near-term objectives and I was wondering if you could elaborate on how you saw that playing out both this year and over time?

Brad Johnson -- President and Chief Executive Officer

Sure. Treating the balance sheet is our priority every day when we come to work. It is our front of mind focus as we run our business and so it was a focus for us at '18 with some significant achievement on that front and it will continue to be a focus for us in 2019 going forward.

David Honeyfield -- Chief Financial Officer

Brad, maybe to add a little bit of color on to that too. Certainly, we've had a handful of successes here and Kevin, certainly as you know, the debt exchange that took place in December was very meaningful. We've had the ability to under the basket in our indenture, do some more of that and we were able to reduce debt a little bit further. Clearly, there are some things that are in our control on the operating side that we're working on. Jay mentioned the -- some of the savings from the 2-string design on the capital program, I mean if you think about applying 10% savings across our capital program on a per well basis, that's a significant decrease in the CapEx for the same result and that math would be $30 million plus.

Other things I'd mention are the way that we're managing the hedge book right now. As I mentioned before, we do have the requirement out there, but that requirement has some flexibility in terms of the products we use. So as we're starting to look forward and put some of that hedging in place, some of the hedging we do is to be in compliance and some of the hedging we do is to be opportunistic. So when we see kind of PIKs come up, we are trying to be very quick to jump on those where we're putting in the -- some of the required hedging in the forward market where there might be some tougher pricing. We're trying to set them up in ways that allow us a lot of flexibility and that's using some costless collars and using the deferred put or deferred premium puts.

So what that does and kind of works in over time, those are things we can control, certainly from a market perspective, I think it's always helpful to remind folks that our production base is significant and you think about the impact that a quarter, that Mcf has on the overall cash flows. On the top line basis that's $60 million. And when you think about our gross margin, those can be meaningful numbers.

So, while we do have hedging in there with the passage of time, these are all the things that we just want to make sure people remember when we talk about the potential for the Company and hopefully that's something that you can add to the list of the items of the Company you can manage and control, and then the items that frankly benefit the Company with a little bit of tailwinds here.

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Okay, thank you. Just to follow up with the flexibility you mentioned on managing your forward hedge strategy, does that also allow for you to look at the existing hedge book and maybe reconfigure that within the required parameters?

David Honeyfield -- Chief Financial Officer

We do have a lot of flexibility in that regard, not that there have been huge dollars, but I think if you were to try to add up what we lift in terms of our hedges that we're in place last time we talked and then the new things that we put on, you'll see that for example on oil, we took off a couple of thousand barrels a day in the first quarter and then a little bit later in the year when we saw that dip in oil price that took place in December and January and that created some immediate cash flow for us.

The ability to restructure the hedges I think on the natural gas side, that's a little bit more challenging, if you're seeing pricing run up and I don't know that you want to necessarily defer all that, but as long as we're staying above those hedged threshold levels with the banks, we have a lot of flexibility in terms of how we manage that book on a day-to-day basis.

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Okay, thank you.

David Honeyfield -- Chief Financial Officer

Thank you.

Operator

Thank you. Our next question comes from a new Anup Goswami from Cantor. Please go ahead.

Anup Goswami -- Cantor Fitzgerald L.P -- Analyst

Hi. The Rockies basis looks like it's positive in the fourth quarter after being much more negative earlier on in 2018. Just wondering if you could talk about what drove that, and where you expect that to go this year?

David Honeyfield -- Chief Financial Officer

Sure. Anup, I'll add a few comments here and then Brad will probably have a couple more to add on to it, but I think Rockies basis is an interesting thing in all parts because I think folks know there's a lot of excess takeaway in the basin. So it's not a supply/demand constraint in terms of not being able to get gas out of the market. We actually included a marketing snapshot slide in the appendix to our deck. As folks know we traded Opal and that's where our delivery point and our price point is.

So a lot of that gas goes into the Southern California market, a lot of that goes up Ruby and into the Pacific Northwest. So what we saw in fourth quarter were maybe a combination of items, fourth quarter and into the first quarter here frankly. There was the pipeline interruption that took place, I think that was in late November, early December on product coming down from Canada. That created a little bit of a -- frankly a demand pull that people were bidding up basis to make sure they were getting delivery for power. Certainly, we've seen more constructive pulls than (ph) just raw demand, out of the Western United States that's been somewhat weather-driven.

The other thing that's interesting is that there is a little bit of a constraint in terms of the ability for some of the California utilities to put gas into storage and to take gas out because of some of the issues with Aliso Canyon from a few years ago, there's just a limited rate. So those markets tend to rely more heavily on really just in time deliveries.

And then as we look forward, I think the couple of things that I look at is, you see it in the -- like the morning storage report and where people are estimating winter storage will end up. For the first time in, gosh a lot of years, you're seeing that prediction of winter storage number almost hitting -- coming outside of the five-year range and it's one of the lowest levels it's been in years and years.

It takes time to refill that storage and I think based on our view whatever kind of excess capacity is in the market, that's what's going to be necessary to fill storage over the summer. So I think that creates a nice situation partially for hub, but also partially for basis. The other thing that I think about is when we look at some of the pipe builds that are happening down in the Permian, the two Kinder Morgan pipes specifically and then a couple of the projects in the east, to me what that does is it keeps product flowing into its more natural markets and as opposed to seeing product move all over the country, whether it's on paper or physically, overall, there is a lot of transportation revenues that are being generated by somebody there in terms of basis differential and I think as product starts to move more into its more local natural markets, I think that starts to put a little bit of a reduced pressure on basis overall.

So, I can't sit here and tell you that I think basis is going to a dime (ph) in the Rockies, but I do think that the picture right now tells you that certainly over 2019, it has gotten much more constructive. I think we put a specific trade on the other day for the third quarter, below $0.30 (ph). So you're just seeing some fundamental items in the market that are pretty helpful.

Anup Goswami -- Cantor Fitzgerald L.P -- Analyst

Appreciate that. Thank you.

Operator

Thank you. I show no further questions in the queue. At this time, I'd like to turn the call over to Brad Johnson, President and Chief Executive Officer for closing remarks.

Brad Johnson -- President and Chief Executive Officer

I wish to thank everyone for joining us today and have a great day.

Operator

Thank you, ladies and gentlemen for attending today's conference. This concludes the program. You may all disconnect. Good day.

Duration: 46 minutes

Call participants:

Aaron Vandeford -- Investor Relations Coordinator

Brad Johnson -- President and Chief Executive Officer

Jerald Jay Stratton -- Chief Operating Officer

David Honeyfield -- Chief Financial Officer

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Michael Scialla -- Stifel, Nicolaus & Company -- Analyst

Kevin Kuzio -- First Eagle Investment Management -- Analyst

Anup Goswami -- Cantor Fitzgerald L.P -- Analyst

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