However, the remainder of the system had a very solid third quarter with pipeline earnings up nearly 45% on the strength of Supply Corporation's recent rate settlement and stable utility earnings, in spite of the COVID pandemic.
In fact, earlier this week Seneca's gross natural gas production crossed the 1 Bcf per day threshold.
With the added scale, we expect to realize immediate cost synergies and you can see that in our guidance on cash operating costs, which we expect will be down about $0.05 per Mcfe in '21.
As I described a few months ago, the plan was to finance the deal with roughly 50-50 debt and equity, and I'm happy to say that we achieved that objective.
In May, we issued $500 million of bonds, the proceeds from which were used to fund the debt component of the acquisition and to term out our revolver.
We also raised just under $175 million through a common equity offering that was done at a better price than we would have received under the equity backstop arrangement available to us under the Shell purchase-and-sale agreement.
And lastly, earlier this week, we signed an agreement to divest substantially all of our Appalachian timber properties for approximately $116 million, which will fund the remaining equity needed for the transaction.
Reinvesting the proceeds from the sale allows us to avoid issuing another roughly 2 million common shares at the midpoint of our fiscal 2021 guidance.
That saves approximately $0.08 per share of dilution.
As you can see in last night's release, the midpoint of our production guidance is 320 Bcfe, a 32% increase over our expected production for fiscal 2020.
In addition with the NYMEX strip in the $2.65 to $2.75 area, there is cause for optimism on natural gas prices and we've been aggressive with our hedging program.
On top of that, as a result of moving to a single rig program, capital spending at Seneca and NFG midstream is expected to decrease by $105 million or about 25%.
So, putting it all together, assuming the current strip, next year we expect more than $150 million in free cash flow from our E&P and gathering businesses.
Once it's fully in service, which we expect will occur by the end of September, this project will add $25 million in annual revenues.
And as a reminder the expansion portion of this project is expected to add $35 million in annual revenue.
As I discussed on last quarter's call, new rates went into effect this past February and are expected to add $35 million in annual revenues.
On the later of the in-service date of that project or April 2022, a step up in rates will go into effect, providing an incremental $15 million in annual revenues.
In total, the expansion projects and rate case settlement are expected to provide in excess of $100 million of incremental annual revenues for our pipeline business by mid-2022.
To put that in perspective, our fiscal 2019 pipeline revenues were $288 million.
At the time of closing these shallow declining properties were producing around 220 million cubic feet per day net.
This additional scale is expected to be immediately accretive to Seneca's cost structure and to put this into context our G&A expense as a result of the Shell acquisition is expected to increase, less than 5% in fiscal '21, while our net production is expected to increase by over 30%.
In addition, we've also acquired valuable low cost pipeline capacity, including 200 million a day of firm transport on National Fuel's Empire system and 100 million a day on Dominion.
Turning to our third quarter, Seneca had strong operational results, producing 56 Bcfe, an increase of around 2% compared to last year's third quarter despite 7.3 Bcf price related curtailments.
In response to sustained, low natural gas prices, we reduced our activity to a single rig in June and have since curtailed an additional 2 Bcf of production in the month of July.
We have now curtailed around 13 Bcf of our gas production so far this year.
We continue to drive down our well costs and have seen an 18% to 20% improvement this year compared to last.
In California, we produced around 584,000 barrels of oil during the third quarter, an increase of 2% over last year's third quarter.
Fortunately, with approximately 80% of our oil production hedged for remainder of the year at an average price of about $60 per barrel.
Taking into account our price-related natural gas production curtailments, we are decreasing our fiscal '20 production guidance slightly to range between 240 to 245 Bcfe.
We are reiterating our capex range of $375 million to $395 million around 20% lower than fiscal '19 at the midpoint.
We are currently planning to remain at a one rig pace in Pennsylvania, due to our lower activity level with only a single rig and completion crew operating in Pennsylvania, our $290 million to $330 million range of capital expenditures for the year represents a 20% decrease at the midpoint of our fiscal '20 guidance and a 35% decrease from fiscal '19.
Fiscal '21 net production is expected to be in the range of 305 to 335 Bcfe, a 32% increase versus fiscal '20.
With only a single rig operating in Pennsylvania, we plan to bring to production 32 wells next year, 16 Marcellus and 16 Utica.
As to production cadence, 27 of the 32 wells are to be brought on line during the first seven months of our fiscal year.
In California, we have deferred our development program until oil prices improve and therefore we are only currently forecasting to spend around $10 million in capex next year.
However, if prices improve we will move to quickly return to our development program and with approximately 49% of our oil production hedged in fiscal '21 at an average price of $58 per barrel, we will continue to generate free cash flow even at today's low prices.
In fiscal '21 through physical firm sales contracts, as well as our firm transport capacity, we have secured marketing outlets for around 91% of our expected Appalachian production and two-thirds protected with price certainty where the downside production -- protection of callers with a floor at $2.37.
That leaves only 9% available for sale onto the spot market.
GAAP earnings per share were $0.47 for the third quarter, adjusting for items impacting comparability, including the ceiling test impairment charge recorded in our E&P segment, adjusted operating results were $0.57 per share, a decrease of $0.14 from the prior year.
As it relates to fiscal '20 our updated earnings guidance is $2.75 to $2.85 per share, a decrease of $0.10 at the midpoint.
As John mentioned, the largest decrease can be attributed to price related curtailments during the third quarter and approximately 6 Bcf of additional curtailments expected during the fourth quarter.
We are initiating preliminary guidance in the range of $3.40 to $3.70 per share, an increase of nearly 27% at the midpoint.
For reference, a $0.10 change in natural gas prices is expected to impact earnings by $0.11 per share, a $5 change in oil by $0.04 per share.
Production is expected to be up nearly 80 Bcfe at the midpoint, in excess of 30% from fiscal '20, the bulk of which comes from the acquired assets.
All of this incremental production will flow through our gathering systems and is expected to lead to $185 million to $200 million in revenue for our Gathering segment.
This is an increase of approximately $50 million from fiscal '20 or approximately 35% of the midpoint.
A portion of this revenue growth will be offset with slightly higher expenses related to the acquisition, where we now expect O&M expense in the segment to be approximately $0.08 to $0.09 per Mcfe of gross throughput.
We generally assume a 25 year depreciable life on these assets, which will drive an $8 million to $9 million increase in depreciation in the Gathering segment.
For the first nine months of fiscal '20 weather was 8% to 11% warmer than normal across our service territory.
This reduced margin by about $5 million, the majority of which was in our Pennsylvania service territory, where we do not have a weather normalization costs.
In addition to normal weather, we are forecasting a continued increase in margin related to our system modernization tracker in New York, which we expect will add approximately $3 million to margin in fiscal '21.
Going to the other direction is a modest 1% to 2% increase in O&M expense in line with inflation.
Touching briefly on the Pipeline and Storage segment, we expect revenues to increase approximately 10%, driven by the full year impact of the supply rate case, of which we only saw eight months of impact in fiscal '20 on the Empire North project, both of which Dave touched on earlier.
Collectively, these items will add approximately $35 million in revenue next year.
On the expense side, we expect O&M to increase by approximately 3% to 4%, partially driven by general inflationary assumptions and the remainder due to expenses from the operation of two new compressor stations associated with the Empire North expansion project.
From a financing perspective, given our relatively flat capital spending forecast and 25% plus forecasted earnings growth, we anticipate generating in-excess of $100 million in consolidated free cash flow in fiscal '21, exclusive of our dividends.

Summary:
GAAP earnings per share were $0.47 for the third quarter, adjusting for items impacting comparability, including the ceiling test impairment charge recorded in our E&P segment, adjusted operating results were $0.57 per share, a decrease of $0.14 from the prior year.
We are initiating preliminary guidance in the range of $3.40 to $3.70 per share, an increase of nearly 27% at the midpoint.