Given the efficiencies realized today, we will be able to accelerate the completion of timing of several pads we had scheduled for early ’24 and therefore, able to absorb that D&C spend in ’23. As discussed on prior calls, we allocated 100% of our D&C capital to oil development through the third quarter. Currently, we have moved one of the two rigs back to our Webb County gas area where we are further testing the Austin Chalk formation. We expect our two-rig program to remain split between oil and gas drilling through year-end. And as always, we remain flexible on our capital allocation as we optimize our drill schedule and completion activity accordingly. With that, I’ll turn it over to Chris.
Chris Abundis: Thanks, Steve. In my comments this morning, I will highlight our third quarter financial results as well as our price realizations, hedging program operating costs and capital structure. I will then also provide a brief update on our announced Chesapeake transaction and our pro forma capital structure. Third quarter oil and gas sales were $174 million excluding derivatives with oil representing 26% of production and 65% of sales. Of note, oil represented just 30% of third quarter sales one year ago. During the quarter, our realized oil price was 97% of NYMEX WTI. Our realized gas price was 90% of NYMEX Henry Hub, and our realized NGL price was 26% of NYMEX WTI. Year-to-date, our realized gas price has been impacted by widening basis differentials and is lower than our historical range compared to Henry Hub.
More recently, we have observed differentials that are closer to historical averages, as the regional market has become more balanced. Risk management is a key aspect of our business, and we are proactive in adding bases to further supplement our hedging strategy. For 2023 and 2024, we have secured gas basis hedges on 150 and 180 MMcf per day respectively to mitigate further risks. Our realized hedging gain on contracts for the quarter was approximately $18 million. Based on our edge book as of October 27, for the remainder of 2023, we have approximately 200 MMcf per day of natural gas hedged, 11,100 barrels per day of oil hedged, 3750 barrels per day of NGL hedged. Using the midpoint of our production guidance, we are 92% hedged on gas and 66% edged on oil for the remainder of this year.
For 2024, we have approximately 211 MMcf per day of natural gas edged, 11,800 barrels per day of oil edged and 5400 barrels per day of NGL edged. The edged math are inclusive of swaps and collars. A detailed summary of our derivatives contracts is contained in our presentation and our 10-Q filing which we expect to file later today. Our third quarter costs were within or favorable to our third quarter guidance ranges across all categories. Lease operating expenses were $0.71 per Mcfe, the transportation and processing costs were $0.42 per Mcfe. Production taxes were 6% of oil and gas sales. Cash G&A, which excludes stock-based compensation was $3 million for the quarter. For the full year 2023, we are guiding for cash G&A of $17.7 million at the midpoint which implies cash G&A on an Mcfe basis to continue to trend below ’22 levels.
We consider our lien cost structure to be a differentiator when compared to our peers. SilverBow reported a net loss of $5 million for the third quarter, excluding unrealized losses on commodity derivatives net of the tax impact. SilverBow reported adjusted net income of $56 million or approximately $2.42 per diluted share for the third quarter. As reconciled in our earnings materials, we recorded free cash flow of $18 million for the quarter. For the full year, we are increasing our free cash flow guidance to a range of $20 million to $40 million. Turning to our balance sheet, total debt was $648 million. This is a decrease of $78 million from the prior quarter as we generated free cash flow and completed an equity raise in the quarter, offset by a $50 million deposit for the Chesapeake transaction.
