Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
We use derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include fixed-price swaps, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.
Our open oil and natural gas derivative contracts as of September 30, 2017, and as of the date of this filing, are detailed in Note 5 – Derivatives and Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our credit agreement limits the extent to which we can hedge our future production.
As of September 30, 2017, per the terms of our credit agreement, we were allowed to hedge all of our estimated production from our proved developed producing reserves based on the most recent reserve information provided to our lenders. Under these terms, we hedged approximately 92.5% and 98.7% of our available oil and condensate hedge volumes, respectively, and almost 92.4% and 99% of our available natural gas hedge volumes for the remainder of 2017 and 2018, respectively.
Pursuant to the closing of our Fourth Amended and Restated credit agreement on November 1, 2017, we are allowed to hedge expected production volumes in excess of estimated production from our proved developed reserves. The revised provisions in our credit agreement allow us to hedge certain percentages of future monthly production equal to the lesser of internally forecasted production or the average of reported production for the most recent three months. We are allowed to hedge up to 90% of production for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. Pursuant to our updated hedge provisions, we have hedged approximately 95%, 99%, and 23% of our available oil and condensate hedge volumes for the remainder of 2017, 2018, and 2019, respectively. Also, we have hedged 99%, 99%, and 28% of our available natural gas hedge volumes for the remainder of 2017, 2018, and 2019, respectively.
The Company intends to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above to remain significantly hedged for the following 12 to 24 months. We do not enter into derivative instruments for speculative purposes.
Non-GAAP Financial Measures
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
We define Adjusted EBITDA as net income (loss) before interest expense, income taxes and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders. We define distributable cash flow after net working interest capital expenditures as distributable cash flow less net working interest capital