General
CNX Resources Corporation ("CNX," the "Company," or "we," "us," or "our") is a premiere independent oil and gas company focused on the exploration, development, production, gathering, processing and acquisition of natural gas properties primarily in the Appalachian Basin. Our operations are centered on unconventional shale formations, primarily the Marcellus Shale and Utica Shale.
CNX’s wholly owned subsidiary, CNX Gathering LLC, which holds the general partner interest and limited partner interest (previously incentive distribution rights - See Note 25 - Subsequent Events in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K for more information) in CNX Midstream Partners LP (a public master limited partnership), which was formed to own, operate, and develop midstream energy assets to service CNX and third-party production, drilling, and completion activities under long-term service contracts. CNX’s consolidated financial statements include CNX Gathering LLC’s financial position and results of operations beginning after January 3, 2018 (see Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K).
CNX was incorporated in Delaware in 1991, but its predecessors had been mining coal, primarily in the Appalachian Basin, since 1864. In November 2017, CNX completed the tax-free spin-off of its coal business (see Note 5 - Discontinued Operations in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K). CNX entered the natural gas business in the 1980s initially to increase the safety and efficiency of its Virginia coal mines by capturing methane from coal seams prior to mining, which makes the mining process safer and more efficient. The natural gas business grew from the coalbed methane production in Virginia into other unconventional production, including hydraulic fracturing in the Marcellus Shale and Utica Shale in the Appalachian Basin. This growth was accelerated with the 2010 asset acquisition of the Appalachian Exploration & Production business of Dominion Resources, Inc.
CNX currently operates, develops and explores for natural gas in Appalachia (Pennsylvania, West Virginia, Ohio, and Virginia). Our primary focus is the continued development of our Marcellus Shale acreage and delineation and development of our unique Utica Shale acreage and stacked pay opportunity set. We believe that our concentrated operating area, legacy surface acreage position, regional operating expertise, extensive data set from development, as well as from non-operated participation wells and our held-by-production acreage position, provides us a significant competitive advantage over our competitors. Over the past ten years, CNX's natural gas production has grown by approximately 471% to produce a total of 539.1 net Bcfe in 2019.
Our land holdings in the Marcellus and Utica Shale plays cover large areas, provide multi-year drilling opportunities and, collectively, have sustainable lower-risk growth profiles. We currently control approximately 519,000 net acres in the Marcellus Shale and approximately 608,000 net acres that have Utica Shale potential in Ohio, West Virginia, and Pennsylvania. We also have approximately 2.4 million net acres in our coalbed methane play.
Highlights of our 2019 production include the following:
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Total average production of 1,477,120 Mcfe per day;
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94% Natural Gas, 6% Liquids; and
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69% Marcellus, 21% Utica, and 10% coalbed methane.
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At December 31, 2019, our proved natural gas, NGL, condensate and oil reserves (collectively, "natural gas reserves") had the following characteristics:
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8.4 Tcfe of proved reserves;
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57.43% proved developed;
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A reserve life ratio of 15.63 years (based on 2019 production).
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The following map provides the location of CNX's E&P operations by region:
CNX's Strategy and Corporate Values
CNX's strategy is to increase shareholder value through the development and growth of its existing natural gas assets and selective acquisition of natural gas acreage leases within its footprint. Our mission is to empower our team to embrace and drive innovative change that creates long-term per share value for our investors, enhances our communities and delivers energy solutions for today and tomorrow. We will also continue to focus on the monetization of non-core assets to accelerate value creation and to minimize any shortfall between operating cash flows and our capital growth requirements.
CNX defines itself through its corporate values which serve as the compass for our road map and guide every aspect of our business as we strive to achieve our corporate mission:
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Responsibility: Be a safe and compliant operator; be a trusted community partner and respected corporate citizen; act with pride and integrity;
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Ownership: Be accountable for our actions and learn from our outcomes, both positive and negative; be calculated risk-takers and seek creative ways to solve problems; and
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Excellence: Be prudent capital allocators; be a lean, efficient, nimble organization; be a disciplined, reliable, performance-driven company.
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These values are the foundation of CNX's identity and are the basis for how management defines continued success. We believe CNX's rich resource base, coupled with these core values, allows management to create value for the long-term. CNX also believes that natural gas is central to a low-cost, reliable, secure, lower-carbon energy future. Widespread and immediate fuel switching to natural gas is the fastest and most cost-effective means to addressing climate concerns, improving air quality in the developing world, and meeting the increasing demand for cleaner forms of energy. More than a short-term “bridge” fuel that is useful in the transition from more carbon-intensive energy sources to renewable, natural gas is inextricably linked to the long-term success of renewable energy. The EIA forecasts that global natural gas consumption is expected to increase by more than 40% from current levels by the year 2050. Increasing demand for natural gas comes with a variety of economic, environmental, and social benefits, including: reduced emissions, improved energy security, industrial applications and reliable heat.
CNX's Capital Expenditure Budget
In 2020, CNX expects capital expenditures of approximately $530-$610 million. The 2020 budget currently includes $360-$410 million of drilling and completion ("D&C") capital, approximately $95 million of capital associated with land, midstream, and water infrastructure and $80-$100 million of capital for CNX Midstream Partners LP ("CNXM"). The Company continuously evaluates multiple factors to determine incremental activity throughout the year, and as such, may update guidance accordingly.
DETAIL OF OPERATIONS
Our operations are located throughout Appalachia and include the following plays:
Marcellus Shale
We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 519,000 net Marcellus Shale acres at December 31, 2019.
The Upper Devonian Shale formation, which includes both the Burkett Shale and Rhinestreet Shale, lies above the Marcellus Shale formation in southwestern Pennsylvania and northern West Virginia. The Company holds approximately 44,000 acres of incremental Upper Devonian acres; however, these acres have historically not been disclosed separately as they generally coincide with our Marcellus acreage.
On January 3, 2018, the Company acquired the remaining 50% membership interest in CONE Gathering LLC (which has since been renamed CNX Gathering LLC), which holds the general partner interest and limited partner interests (previously incentive distribution rights - See Note 25 - Subsequent Events in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K for more information) in CNXM, the entity that constructs and operates the gathering system for most of our Marcellus shale production. See "Midstream Gas Services" below for a more detailed explanation.
Utica Shale
We have the rights to extract natural gas in Pennsylvania, West Virginia, and Ohio from approximately 608,000 net Utica Shale acres at December 31, 2019. Approximately 349,000 Utica acres coincide with Marcellus Shale acreage in Pennsylvania, West Virginia, and Ohio. During the third quarter of 2018, CNX closed on the sale of substantially all of its Ohio Utica Joint Venture Assets, including approximately 35,000 net acres in the wet gas Utica Shale areas of Belmont, Guernsey, Harrison, and Noble Counties (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
Coalbed Methane (CBM)
We have the rights to extract CBM in Virginia from approximately 308,000 net CBM acres in Central Appalachia. We produce CBM natural gas primarily from the Pocahontas #3 seam and still have a nominal drilling program.
We also have the rights to extract CBM from approximately 2,122,000 net CBM acres in other states including West Virginia, Pennsylvania, Ohio, Illinois, Indiana and New Mexico with no current plans to drill CBM wells in these areas.
Other Gas
We have the rights to extract natural gas from other shale and shallow oil and gas positions primarily in Illinois, Indiana, New York, Ohio, Pennsylvania, Virginia, and West Virginia from approximately 981,700 net acres at December 31, 2019. The majority of our shallow oil and gas leasehold position is held by production and all of it is extensively overlain by existing third-party gas gathering and transmission infrastructure. In March 2018, CNX Gas completed the sale of substantially all of its shallow oil and gas assets in Pennsylvania and West Virginia, including approximately 833,000 net acres (See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
Summary of Properties as of December 31, 2019
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Marcellus
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Utica
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CBM
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Other Gas
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Segment
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Segment
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Segment
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Segment
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Total
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Estimated Net Proved Reserves (MMcfe)
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6,401,288
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910,667
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1,103,724
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9,988
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8,425,667
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Percent Developed
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55
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%
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49
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%
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77
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%
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100
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%
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57
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%
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Net Producing Wells (including oil and gob wells)
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397
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55
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3,943
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115
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4,510
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Net Acreage Position:
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Net Proved Developed Acres
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46,701
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14,101
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274,512
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2,386
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337,700
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Net Proved Undeveloped Acres
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22,737
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6,179
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—
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—
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28,916
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Net Unproved Acres(1)
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494,251
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238,720
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2,156,231
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979,331
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3,868,533
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Total Net Acres(2)
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563,689
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259,000
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2,430,743
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981,717
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4,235,149
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_________
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(1)
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Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
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(2)
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Acreage amounts are only included under the target strata CNX expects to produce with the exception of certain CBM acres governed by separate leases, although the reported acres may include rights to multiple gas seams (e.g. we have rights to the Marcellus segment that are disclosed under the Utica segment and we have rights to Utica segment that are disclosed under the Marcellus segment). We have reviewed our drilling plans, and our acreage rights and have used our best judgment to reflect the acres in the strata we expect to primarily produce. As more information is obtained or circumstances change, the acreage classification may change.
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Producing Wells and Acreage
Most of our development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied.
The following table sets forth, at December 31, 2019, the number of producing wells, developed acreage and undeveloped acreage:
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Gross
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Net(1)
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Producing Gas Wells (including gob wells)
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6,512
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4,510
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Producing Oil Wells
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151
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—
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Net Acreage Position:
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Proved Developed Acreage
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337,700
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337,700
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Proved Undeveloped Acreage
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28,916
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28,916
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Unproved Acreage
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5,192,777
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3,868,533
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Total Acreage
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5,559,393
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4,235,149
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(1)
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Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
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The following table represents the terms under which we hold these acres:
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Gross Unproved Acres
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Net Unproved Acres
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Net Proved Undeveloped Acres
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Held by Production/Fee
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4,354,734
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3,305,639
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21,874
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Expiration Within 2 Years
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43,468
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24,102
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4,235
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Expiration Beyond 2 Years
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47,137
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26,176
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6,325
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Total Acreage
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4,445,339
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3,355,917
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32,434
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The leases reflected above as Gross and Net Unproved Acres with expiration dates are included in our current drill plan or active land program. Leases with expiration dates within two years represent approximately 1% of our total net unproved acres and leases with expiration dates beyond two years represent approximately 1% of our total net unproved acres. In each case, we deemed this acreage to not be material to our overall acreage position. Additionally, based on our current drill plans and lease management we do not anticipate any material impact to our consolidated financial statements from the expiration of such leases.
Development Wells (Net)
During the years ended December 31, 2019, 2018 and 2017, we drilled 75.7, 83.9 and 90.0 net development wells, respectively. Gob wells and wells drilled by operators other than our primary joint venture partners at that time are excluded from net development wells. In 2019, there were 35.0 net development wells and 1.0 exploratory well drilled but uncompleted. There was 1.0 net dry development well in 2019 and no net dry development wells in 2018 or 2017. As of December 31, 2019, there are 7.0 gross completed developmental wells ready to be turned in-line. The following table illustrates the net wells drilled by well classification type:
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For the Year
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Ended December 31,
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2019
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2018
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2017
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Marcellus Segment
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47.0
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65.9
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9.0
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Utica Segment
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17.7
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12.0
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17.0
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CBM Segment
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11.0
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6.0
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64.0
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Other Gas Segment
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—
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—
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—
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Total Development Wells (Net)
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75.7
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83.9
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90.0
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Exploratory Wells (Net)
There were 5.0 and 4.0 net exploratory wells drilled during the years ended December 31, 2019 and 2017, respectively. There were no net exploratory wells drilled during the year ended December 31, 2018. As of December 31, 2019, there is 1.0 net exploratory well in process. The following table illustrates the exploratory wells drilled by well classification type:
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For the Year Ended December 31,
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2019
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2018
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2017
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Producing
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Dry
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Still Eval*.
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Producing
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Dry
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Still Eval.
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Producing
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Dry
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Still Eval.
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Marcellus Segment
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—
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—
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—
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—
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—
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—
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—
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—
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—
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Utica Segment
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4.0
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—
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1.0
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—
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—
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—
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4.0
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—
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—
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CBM Segment
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—
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—
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—
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—
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—
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—
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—
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—
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—
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Other Gas Segment
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—
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—
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—
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—
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—
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—
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—
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—
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—
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Total Exploratory Wells (Net)
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4.0
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—
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1.0
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—
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—
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—
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4.0
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—
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—
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* Still evaluating includes wells that were drilled and uncompleted or in the process of being completed at the end of the year.
Reserves
The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).
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Net Reserves (Million of Cubic Feet Equivalent)
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As of December 31,
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2019
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2018
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2017
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Proved Developed Reserves
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4,838,858
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4,494,878
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4,409,065
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Proved Undeveloped Reserves
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3,586,809
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3,386,457
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3,172,547
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Total Proved Developed and Undeveloped Reserves(1)
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8,425,667
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7,881,335
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7,581,612
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___________
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(1)
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For additional information on our reserves, see Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.
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Discounted Future Net Cash Flows
The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:
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As of December 31,
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2019
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2018
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2017
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(Dollars in millions)
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Future Net Cash Flows
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$
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7,744
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$
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13,132
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$
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7,841
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Total PV-10 Measure of Pre-Tax Discounted Future Net Cash Flows (1)
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$
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4,176
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$
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6,172
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$
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4,140
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Total Standardized Measure of After-Tax Discounted Future Net Cash Flows
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$
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3,070
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$
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4,655
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$
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3,131
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____________
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(1)
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We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principles (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.
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Reconciliation of PV-10 to Standardized Measure
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As of December 31,
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2019
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2018
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2017
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(Dollars in millions)
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Future Cash Inflows
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$
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19,490
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$
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26,610
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$
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19,262
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Future Production Costs
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(7,903
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)
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(7,730
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)
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(7,234
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)
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Future Development Costs (including Abandonments)
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(1,121
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)
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(1,600
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)
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(1,711
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)
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Future Net Cash Flows (pre-tax)
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10,466
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17,280
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|
10,317
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10% Discount Factor
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(6,290
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)
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(11,108
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)
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(6,177
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)
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PV-10 (Non-GAAP Measure)
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4,176
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|
6,172
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|
4,140
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Undiscounted Income Taxes
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(2,721
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)
|
|
(4,147
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)
|
|
(2,476
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)
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10% Discount Factor
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1,615
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|
|
2,630
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|
|
1,467
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Discounted Income Taxes
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(1,106
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)
|
|
(1,517
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)
|
|
(1,009
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)
|
|
Standardized GAAP Measure
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$
|
3,070
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|
|
$
|
4,655
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|
|
$
|
3,131
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Gas Production
The following table sets forth net sales volumes produced for the periods indicated:
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For the Year
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|
Ended December 31,
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|
2019
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2018
|
|
2017
|
|
Natural Gas
|
|
|
|
|
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Sales Volume (MMcf)
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|
|
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Marcellus
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335,993
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|
|
255,127
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|
|
209,687
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Utica
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|
113,676
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|
|
148,117
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|
|
70,708
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|
|
CBM
|
|
55,445
|
|
|
60,268
|
|
|
65,373
|
|
|
Other
|
|
241
|
|
|
4,714
|
|
|
19,125
|
|
|
Total
|
|
505,355
|
|
|
468,226
|
|
|
364,893
|
|
|
|
|
|
|
|
|
|
|
NGL
|
|
|
|
|
|
|
|
Sales Volume (Mbbls)
|
|
|
|
|
|
|
|
Marcellus
|
|
5,423
|
|
|
5,227
|
|
|
4,604
|
|
|
Utica
|
|
5
|
|
|
853
|
|
|
1,851
|
|
|
Other
|
|
—
|
|
|
1
|
|
|
1
|
|
|
Total
|
|
5,428
|
|
|
6,081
|
|
|
6,456
|
|
|
|
|
|
|
|
|
|
|
Oil and Condensate
|
|
|
|
|
|
|
|
Sales Volume (Mbbls)
|
|
|
|
|
|
|
|
Marcellus
|
|
186
|
|
|
286
|
|
|
346
|
|
|
Utica
|
|
9
|
|
|
78
|
|
|
204
|
|
|
Other
|
|
8
|
|
|
35
|
|
|
39
|
|
|
Total
|
|
203
|
|
|
399
|
|
|
589
|
|
|
|
|
|
|
|
|
|
|
Total Sales Volume (MMcfe)
|
|
|
|
|
|
|
|
Marcellus
|
|
369,652
|
|
|
288,203
|
|
|
239,387
|
|
|
Utica
|
|
113,761
|
|
|
153,704
|
|
|
83,038
|
|
|
CBM
|
|
55,445
|
|
|
60,268
|
|
|
65,373
|
|
|
Other
|
|
291
|
|
|
4,929
|
|
|
19,368
|
|
|
Total
|
|
539,149
|
|
|
507,104
|
|
|
407,166
|
|
*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas.
Note: 2018 production includes approximately 27 Bcfe of production related to assets that were sold during the year. For additional information, see Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K, which is incorporated herein by reference.
CNX expects a minimum base for 2020 annual natural gas production volumes of 525-555 Bcfe, which is consistent with 2019 volumes, based on the midpoint of guidance.
Average Sales Price and Average Lifting Cost
The following table sets forth the total average sales price and the total average lifting cost for all of our natural gas and NGL production for the periods indicated. Total lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Part II. Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K for a breakdown by segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year
|
|
|
|
Ended December 31,
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
Average Sales Price - Gas (Mcf)
|
|
$
|
2.48
|
|
|
$
|
2.97
|
|
|
$
|
2.59
|
|
|
Gain (Loss) on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf)
|
|
$
|
0.14
|
|
|
$
|
(0.15
|
)
|
|
$
|
(0.11
|
)
|
|
Average Sales Price - NGLs (Mcfe)*
|
|
$
|
3.20
|
|
|
$
|
4.55
|
|
|
$
|
4.03
|
|
|
Average Sales Price - Oil (Mcfe)*
|
|
$
|
8.13
|
|
|
$
|
9.89
|
|
|
$
|
7.56
|
|
|
Average Sales Price - Condensate (Mcfe)*
|
|
$
|
7.47
|
|
|
$
|
8.43
|
|
|
$
|
6.59
|
|
|
|
|
|
|
|
|
|
|
Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments
|
|
$
|
2.66
|
|
|
$
|
2.97
|
|
|
$
|
2.66
|
|
|
Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments
|
|
$
|
2.53
|
|
|
$
|
3.11
|
|
|
$
|
2.76
|
|
|
Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe)
|
|
$
|
0.12
|
|
|
$
|
0.19
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price - NGLs (Bbl)
|
|
$
|
19.20
|
|
|
$
|
27.30
|
|
|
$
|
24.18
|
|
|
Average Sales Price - Oil (Bbl)
|
|
$
|
48.78
|
|
|
$
|
59.34
|
|
|
$
|
45.36
|
|
|
Average Sales Price - Condensate (Bbl)
|
|
$
|
44.82
|
|
|
$
|
50.58
|
|
|
$
|
39.54
|
|
*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas.
Sales of NGLs, condensates and oil enhance our reported natural gas equivalent sales price. Across all volumes, when excluding the impact of hedging, sales of liquids added $0.05 per Mcfe, $0.14 per Mcfe, and $0.17 per Mcfe for 2019, 2018, and 2017, respectively, to average gas sales prices. CNX expects to continue to realize a liquids uplift benefit as additional wells are turned-in-line, primarily in the liquid-rich areas of the Marcellus shale. We continue to sell the majority of our NGLs through the large midstream companies that process our natural gas. This approach allows us to take advantage of the processors’ transportation efficiencies and diversified markets. Certain of CNX’s processing contracts provide for the ability to take our NGLs “in-kind” and market them directly if desired. The processed purity products are ultimately sold to industrial, commercial, and petrochemical markets.
We enter into physical natural gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, we have delivered quantities required under these contracts. We also enter into various natural gas swap transactions. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 389.2 Bcf of our produced gas sales volumes for the year ended December 31, 2019 at an average price of $2.70 per Mcf. The notional volumes associated with these gas swaps represented approximately 356.3 Bcf of our produced gas sales volumes for the year ended December 31, 2018 at an average price of $2.76 per Mcf. As of January 8, 2020, these physical and swap transactions represent approximately 497.5 Bcf of our estimated 2020 production at an average price of $2.55 per Mcf, 443.3 Bcf of our estimated 2021 production at an average price of $2.42 per Mcf, 305.2 Bcf of our estimated 2022 production at an average price of $2.44 per Mcf, approximately 174.1 Bcf of our estimated 2023 production at an average price of $2.29 per Mcf, and approximately 151.5 Bcf of our estimated 2024 production at an average price of $2.32 per Mcf.
CNX's hedging strategy and information regarding derivative instruments used are outlined in Part II. Item 7A. "Qualitative and Quantitative Disclosures About Market Risk" and in Note 21 - Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
Midstream Gas Services
E&P Midstream Gas Services
CNX has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead to interstate pipelines or other local sales points. In addition, over time CNX has acquired extensive gathering assets. CNX now owns or operates approximately 2,600 miles of natural gas gathering pipelines as well as a number of natural gas processing facilities. These assets are part of the E&P Division (See Note 24 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
CNX's Midstream Division (see below) owns substantially all of CNX's Marcellus Shale gathering systems which also transports CNX's Utica Shale volumes in Pennsylvania. With respect to the Utica Shale in Ohio, CNX primarily contracts with third-party gathering services.
CNX has developed a diversified portfolio of firm transportation capacity options to support its production growth plan. CNX plans to selectively acquire firm capacity on an as-needed basis, while minimizing transportation costs and long-term financial obligations. Optimization of our firm transportation portfolio may also include, from time to time and as appropriate, releasing firm transportation to others. CNX also benefits from the strategic location of our primary production areas in southwestern Pennsylvania, northern West Virginia, and eastern Ohio. These areas are currently served by a large concentration of major pipelines that provide us with access to major gas markets without the necessity of transporting our gas out of the region, and it is expected that recently-approved and pending pipeline projects will increase the take-away capacity from our region. In addition to firm transportation capacity, CNX has developed a processing portfolio to support the projected volumes from its wet gas production areas and has the operational and contractual flexibility to potentially convert a portion of currently processed wet gas volumes to be marketed as dry gas volumes, or vice-versa, as economically appropriate.
CNX has the advantage of having natural gas production from CBM and lower Btu Utica wells in close proximity to higher Btu Marcellus wells. Separately, the low Btu CBM gas and the high Btu Marcellus gas may need processing in order to meet downstream pipeline specifications. However, the geographic proximity and interconnected gathering system servicing these wells allow CNX to blend this gas together and in some cases eliminate the need for the costly processing of gas that does not meet pipeline specification. These different gas types allow us more flexibility in bringing Marcellus and Utica shale wells on-line at qualities that meet interstate pipeline specifications.
Midstream Division
In January 2018, CNX acquired Noble Energy’s ("Noble") 50% membership interest in CNX Gathering LLC (then named CONE Gathering) ("CNX Gathering"), which holds the general partner interest and limited partner interests (previously incentive distribution rights) in CNX Midstream Partners LP (then named CONE Midstream Partners LP) ("CNX Midstream" or "CNXM"). See Note 6 - Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information. As part of the transaction, CNX Midstream amended its gas gathering agreement with CNX Gas Company LLC, a wholly-owned subsidiary of CNX.
CNX Gathering develops, operates and owns substantially all of CNX’s Marcellus Shale gathering systems. Prior to its acquisition of Noble’s interest, CNX accounted for its interest in CNX Gathering under the equity method of accounting. Subsequent to the acquisition, CNX is the single sponsor of CNXM, and beginning in the first quarter of 2018 CNX Gathering was consolidated into the Company’s financial statements as the Midstream Division (See Note 24 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). We believe that the network of rights-of-way, vast surface holdings, experience in building and operating gathering systems in the Appalachian basin, and increased control and flexibility will give CNX Gathering an advantage in building the midstream assets required to execute our future development plans.
Natural Gas Competition
The United States natural gas industry is highly competitive. CNX competes with other large producers, as well as a myriad of smaller producers and marketers. CNX also competes for pipeline and other services to deliver its products to customers. According to data from the Natural Gas Supply Association and the Energy Information Agency (EIA), the five largest U.S. producers of natural gas produced about 14% of dry natural gas production during the first ten months of 2019. The EIA reported 522,631 producing natural gas wells in the United States at December 31, 2018 (the latest year for which government statistics are available), which is approximately 3% lower than 2017.
CNX expects natural gas to continue to be a significant contributor to the domestic electric generation mix in the long-term, as well as to fuel industrial growth in the U.S. economy. According to the EIA, natural gas represented 38% of U.S. electricity generation during the twelve months ended October 31, 2019, up from 35% in 2018. Estimates from EIA indicate that an average of 31.0 billion cubic feet per day (Bcf/d) was consumed by electric generation in 2019, up 7% from 2018. EIA also reports that the United States exported 5.3 Bcf/d in 2019 which is up 2.0 Bcf/d, or about 61% from 2018. EIA expects this trend to persist with estimates pointing towards an increase to 7.3 Bcf/d in 2020 and 8.9 Bcf/d in 2021. The United States became a net exporter of natural gas on an annual basis in 2016 for the first time in almost 60 years. U.S. natural gas exports have increased primarily with the addition of new LNG export facilities in the Lower 48 states. EIA reported that in 2019, the United States averaged LNG exports of 5.0 Bcf/d with expectations of steady increases to 6.5 Bcf/d and 7.7 Bcf/d in 2020 and 2021, respectively. CNX expects the high level of U.S. gas exports to continue in the future. In addition, there is potential for natural gas to become a significant contributor to the transportation market. The EIA currently expects overall demand for U.S. natural gas in 2020 to increase 1.7% from 2019. Our increasing gas production will allow CNX to participate in growing markets.
CNX gas operations are primarily located in the eastern United States, specifically the Appalachian Basin. The gas market is highly fragmented and not dominated by any single producer. We believe that competition among producers is based primarily on acreage position, low drilling and operating costs as well as pipeline transportation availability to the various markets.
Continued demand for CNX's natural gas and the prices that CNX obtains are affected by natural gas use in the production of electricity, pipeline capacity, weather, U.S. manufacturing and the overall strength of the economy, environmental and government regulation, technological developments, the availability and price of competing alternative fuel supplies, and national and regional supply/demand dynamics.
Non-Core Mineral Assets and Surface Properties
CNX owns significant natural gas assets that are not in our short-term or medium-term development plans. We continually explore the monetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination of the foregoing in order to bring the value of these assets forward for the benefit of our shareholders. We also control a significant amount of surface acreage. This surface acreage is valuable to us in the development of the gathering system for our Marcellus Shale and Utica Shale production. We also derive value from this surface control by granting rights of way or development rights to third-parties when we are able to derive appropriate value for our shareholders.
Water Division
CNX Water Assets LLC ("CNX Water") is a wholly-owned subsidiary of CNX and supplies turnkey solutions for water sourcing, delivery and disposal for our natural gas operations, and supplies solutions for water sourcing as well as delivery and disposal for third parties. In coordination with our midstream operations, CNX Water works to develop solutions that coincide with our midstream operations to offer gas gathering and water delivery solutions in one package to third parties.
Employee and Labor Relations
At December 31, 2019, CNX had 467 employees, none of whom are subject to a collective bargaining agreement.
Industry Segments
Financial information concerning industry segments, as defined by GAAP, for the years ended December 31, 2019, 2018 and 2017 is included in Note 24 - Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K and is incorporated herein by reference.
Financial Information about Geographic Areas
All of the Company's assets and operations are located in the continental United States.
Laws and Regulations
General
Our natural gas and midstream operations are subject to various federal, state and local (including county and municipal level) laws and regulations. These laws and regulations cover virtually every aspect of our operations including, among other things: use of public roads; construction of well pads, impoundments, tanks and roads; pooling and unitizations; water withdrawal and procurement for well stimulation purposes; well drilling, casing and hydraulic fracturing; stormwater management; well production; well plugging; venting or flaring of natural gas; pipeline construction and the compression and transmission of natural gas and liquids; reclamation and restoration of properties after natural gas operations are completed; handling, storage, transportation and disposal of materials used or generated by natural gas operations; the calculation, reporting and payment of taxes on gas production; and gathering of natural gas production. Numerous governmental permits, authorizations and approvals under these laws and regulations are required for natural gas and midstream operations. These laws and regulations, and the permits, authorizations and approvals issued pursuant to those laws and regulations, are intended to protect, among other things: air quality; ground water and surface water resources, including drinking water supplies; wetlands; waterways; endangered plants and wildlife; state natural resources and the health and safety of our employees and the communities in which we operate.
Additionally, the electric power generation industry, which consumes significant quantities of natural gas, remains subject to extensive regulation regarding the environmental impact of its power generation activities, which could impact demand for our natural gas.
We endeavor to conduct our natural gas and midstream operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions, permit exceedances and violations during operations can and do occur. Such exceedances and violations generally result in fines or penalties but could make it more difficult for us to obtain necessary permits in the future. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our natural gas or midstream operations or on our customers' ability to use our natural gas and may require us or our customers to change their operations significantly or incur substantial costs. See “Risk Factors -- Existing and future governmental laws, regulations and other legal requirements and judicial decisions that govern our business may increase our costs of doing business and may restrict our operations” for additional discussion regarding additional laws and regulations affecting our business, operations and industry.
Environmental Laws
Many of the laws and regulations referred to above are state level environmental laws and regulations, which vary according to the state in which we are conducting operations. However, our natural gas and midstream operations are also subject to numerous federal level environmental laws and regulations.
In addition to routine reviews and inspections by regulators to confirm compliance with applicable regulatory requirements, CNX has established protocols for ongoing assessments to identify potential environmental exposures. These assessments take into account industry and internal best management practices and evaluate compliance with laws and regulations and include reviews of our third-party service providers, including, for instance, waste management facilities.
Hydraulic Fracturing Activities. Hydraulic fracturing is typically regulated by state oil and natural gas commissions and similar agencies, but the U.S. Environmental Protection Agency (“EPA”) has asserted certain regulatory authority over hydraulic fracturing and has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells, and has disclosed its intent to develop regulations to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Some states, including states in which we operate, have adopted regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. Additionally, these federal requirements and proposals may be subject to further review and revision by the EPA.
Scrutiny of hydraulic fracturing activities also continues in other ways at the federal and local levels. For example, in June 2015, the EPA issued its draft report on the potential impacts of hydraulic fracturing on drinking water and groundwater. The draft report found no systemic negative impacts from hydraulic fracturing. In December 2016, the EPA released its final report on the impacts of hydraulic fracturing on drinking water. While the language was changed and included the possibility of negative impacts from hydraulic fracturing, it also included the guidance to industry and regulators on how the process can be performed safely. We cannot predict whether any other legislation or regulations will be enacted and, if so, what its provisions will be.
Clean Air Act. The federal Clean Air Act and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. Various activities in our operations are subject to air quality regulation, including pipeline compression, venting and flaring of natural gas, and hydraulic fracturing and completion processes, as well as fugitive emissions from operations. We obtain permits, typically from state or local authorities, to conduct these activities. Additionally, we are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. Further, some states and the federal government have proposed that emissions from certain proximate and related sources should be aggregated to provide for regulation and permitting of a single, major source. Federal and state governmental agencies continue to investigate the potential for emissions from oil and natural gas activities, and further regulation could increase our cost or temporarily restrict our ability to produce. For example, the EPA sets National Ambient Air Quality Standards for certain pollutants and changes to such standards could cause us to make additional capital expenditures or alter our business operations in some manner. See “Risk Factors - Regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation, could adversely impact the market for natural gas, as well as for our securities.” for additional discussion regarding certain laws and regulations related to air emissions and related matters.
Clean Water Act. The federal Clean Water Act (“CWA”) and corresponding state laws affect our natural gas operations by regulating storm water or other regulated substance discharges, including pollutants, sediment, and spills and releases of oil, brine and other substances, into surface waters, and in certain instances imposing requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers, or a delegated state agency. These permits require regular monitoring and compliance with effluent limitations and reporting requirements and govern the discharge of pollutants into regulated waters. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. See “Risk Factors -Environmental regulations can increase costs and introduce uncertainty that could adversely impact the market for natural gas with potential short and long-term liabilities.” for additional discussion regarding certain laws and regulations related to clean water, the disposal or use of water and related matters.
Endangered Species Act. The Endangered Species Act and related state regulation protect plant and animal species that are threatened or endangered. Some of our operations are located in areas that are or may be designated as protected habitats for endangered or threatened species, including the Northern Long-Eared and Indiana bats, which has a seasonal impact on our construction activities and operations. New or additional species that may be identified as requiring protection or consideration may lead to delays in permits and/or other restrictions.
Safety of Gas Transmission and Gathering Pipelines. Natural gas pipelines serving our operations are subject to regulation by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968, (“NGPSA”), as amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas. Additionally, certain states, such as West Virginia, also maintain jurisdiction over intrastate natural gas lines. See “Risk Factors -- We may incur significant costs and liabilities as a result of pipeline operations and related increase in the regulation of gas gathering pipelines.” for additional discussion regarding gas transmission and gathering pipelines.
Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulations affect natural gas operations by imposing requirements for the management, treatment, storage and disposal of hazardous and non-hazardous wastes, including wastes generated by natural gas operations. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective action orders issued by the EPA that could adversely affect our financial results, financial condition and cash flows. On December 28, 2016 the EPA entered into a consent order to resolve outstanding litigation brought by environmental and citizen groups regarding the applicability of RCRA to wastes from oil and gas development activities. In April 2019, the EPA issued a report concluding that revisions to the federal regulations for the management of exploration and production wastes under RCRA were not necessary at the time the report was issued. We cannot predict whether the EPA may change its conclusion at some point, or whether any other legislation or regulations will be enacted and if so, what its provisions will be.
Federal Regulation of the Sale and Transportation of Natural Gas
Federal Energy Regulatory Commission. Regulations and orders issued by the Federal Energy Regulatory Commission (FERC) impact our natural gas business to a certain degree. Although the FERC does not directly regulate our natural gas production activities, the FERC has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the FERC has jurisdiction over the transportation of natural gas in interstate commerce, and regulates the terms, conditions of service, and rates for the interstate transportation of our natural gas production. The FERC possesses regulatory oversight over natural gas markets, including anti-market manipulation regulation. The FERC has the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties for violations of the Natural Gas Act or the FERC’s regulations and policies thereunder.
Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from regulation by the FERC. However, the distinction between federally unregulated gathering facilities and FERC-regulated transmission facilities is a fact-based determination, and the classification of such facilities may be the subject of dispute and, potentially, litigation. We own certain natural gas pipeline facilities that we believe meet the traditional tests which the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.
Natural gas prices are currently unregulated, but Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas sales might be enacted in the future or what effect, if any, any such legislation might have on our operations.
Health and Safety Laws
Occupational Safety and Health Act. Our natural gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) and comparable state laws in some states, all of which regulate health and safety of employees at our natural gas operations. Additionally, OSHA's hazardous communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state laws require that information be maintained about hazardous materials used or produced by our natural gas operations and that this information be provided to employees, state and local governments and the public.
Climate Change Laws and Regulations
Climate change continues to be a legislative and regulatory focus. There are a number of proposed and final laws and regulations that limit greenhouse gas emissions, and regulations that restrict emissions could increase our costs should the requirements necessitate the installation new equipment or the purchase of emission allowances. These laws and regulations could also impact our customers, including the electric generation industry, making alternative sources of energy more competitive. Additional regulation could also lead to permitting delays and additional monitoring and administrative requirements, as well as to impacts on electricity generating operations. See “Risk Factors - Regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets and such regulation, as well as uncertainty concerning such regulation, could adversely impact the market for natural gas, as well as for our securities.” for additional discussion regarding certain laws and regulations related to climate change, greenhouse gas and related matters.
Title to Properties
CNX acquires ownership or leasehold rights to oil and natural gas properties prior to conducting operations on those properties. The legal requirements of such ownership or leasehold rights generally are established by state statutory or common law. As is customary in the natural gas industry, we have generally conducted only a summary review of the title to oil and gas rights that are not yet in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records. Prior to the commencement of development operations on natural gas and coalbed methane properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. Our discovering title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimated gas reserves including our proved undeveloped reserves. In accordance with the foregoing, we have completed title work on substantially all of our natural gas and coalbed methane properties that are currently producing and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.
Available Information
CNX maintains a website at www.cnx.com. CNX makes available, free of charge on its website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are electronically filed with, or furnished to the SEC. Those reports are also available at the SEC's website www.sec.gov. Apart from SEC filings, we also use our website to publish information which may be important to investors, such as presentations to analysts.
Information About Our Executive Officers
Incorporated by reference into this Part I is the information set forth in Part III. Item 10 under the caption “Information About Our Executive Officers” (included herein pursuant to Item 401(b) of Regulation S-K).
