ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 000-19514
Gulfport Energy Corporation
(Exact Name of Registrant As Specified in Its Charter)
(State or Other Jurisdiction of Incorporation or Organization)
(IRS Employer Identification Number)
3001 Quail Springs Parkway
(Address of Principal Executive Offices)
(Registrant Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share
The Nasdaq Stock Market LLC
Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐No☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files).
Yes☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer☒ Accelerated filer ☐ Non-accelerated filer ☐
Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of our common stock held by non-affiliates on June 28, 2019 was $782,634,443. As of February 14, 2020, there were 159,710,955 shares of our $0.01 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
This Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), the effect of our remediation plan for a material weakness, business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements.
These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.
Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in Item 1A. “Risk Factors” and Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this Form 10-K.
All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.
Investors should note that we announce financial information in SEC filings, press releases and public conference calls. We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of this Annual Report on Form 10-K.
A Delaware corporation formed in 1997, we are an independent natural gas-weighted exploration and production company focused on the exploration, development, acquisition and production of natural gas, crude oil and natural gas liquids ("NGL") in the United States with primary focus in the Appalachia and Mid-Continent basins. Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow. We also seek to opportunistically expand our inventory of economic drilling locations in the basins in which we operate. Our principal properties are located in Eastern Ohio, where we target development in the Utica formation (the “Utica”) and Central Oklahoma where we target development in the SCOOP Woodford and Springer formations (the "SCOOP"). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. In addition, among other interests, we hold an acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC ("Grizzly"), and an approximate 21.8% equity interest in Mammoth Energy Services, Inc. ("Mammoth Energy"), an energy services company listed on the Nasdaq Global Select Market (TUSK), both of which are non-core to our business strategy.
As of December 31, 2019, we had 4.5 trillion cubic feet of natural gas equivalent ("Tcfe") of proved reserves with a standardized measure of discounted future net cash flows of approximately $1.7 billion and a present net value of estimated future net revenues, discounted at 10% ("PV-10"), of approximately $1.7 billion. See "Oil, Natural Gas and NGL Reserves" below for our definition of PV-10 (a non-GAAP financial measure) and a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.
Information About Us
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
Gulfport aims to create shareholder value through the development of our significant resource plays. Our substantial inventory of hydrocarbon resources, including unproved acreage positions in each of our key basins, provides a strong foundation to create future value. Concentrated blocks of unproved acreage provide us the opportunity to apply best in class techniques including optimum well spacing, leading completion practices and lateral length optimization to maximize overall capital efficiency. We have improved our capital and operating efficiency metrics over the last several years and today have a low cost structure in both our Utica and SCOOP operating areas. We believe our low cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategy to continue to seek capital and operating efficiencies to grow this advantage.
We continue to focus on reducing our leverage profile, increasing cash flow from operations, improving margins through financial discipline and operating efficiencies while at the same time maintaining strong environmental and safety performance. To accomplish these goals, we intend to allocate capital expenditures to projects we believe offer the highest rate of return, to deploy leading drilling and completion techniques and technologies in our development efforts, and to take advantage of merger, acquisition and divestiture opportunities to strengthen our cost structure, deepen our inventory and improve our asset portfolio.
We believe that our dedication to financial discipline, the flexibility and efficiency of our capital program, our low cost structure and our continued focus on safety and environmental stewardship provides opportunities for sustainable value creation.
Our 2020 capital expenditure program is expected to be $285 million to $310 million. We expect to fund these expenditures with our operating cash flow and borrowings under our revolving credit agreement. We expect this drilling program to result in 1,100 to 1,150 MMcfeper day of production in 2020.
We plan to run on average approximately one operated rig in our Utica area and 1.5 rigs in our SCOOP area in 2020. In the Utica, we intend to spud 16 gross operated horizontal wells (14.8 net), and commence sales on 18 gross and net horizontal wells in 2020. In the SCOOP, we intend to spud 10 gross operated horizontal wells (7.8 net), and commence sales on four gross horizontal wells (3.8 net) in 2020.
We focus our development, production and acquisition efforts in the geographic operating areas described below.
Utica (primarily Eastern Ohio) - The Utica Shale is a hydrocarbon bearing rock formation located in the Appalachian Basin of the United States and Canada. We have approximately 205,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio where the Utica Shale ranges in thickness from 600 to over 750 feet. During the fourth quarter of 2019 we produced approximately 1,090 MMcfe per day net to our interests in this area.
SCOOP (Oklahoma) - The SCOOP, or South Central Oklahoma Oil Province, is a loosely defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 76,000 net reservoir acres (comprised of approximately 41,500 in the Woodford formation and approximately 34,500 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During the fourth quarter of 2019, we produced approximately 255 MMcfe per day net to our interests in this area.
Additional Properties - In addition to our core properties discussed above, we also own working interests and overriding royalty interest in various fields including the Bakken formation in North Dakota and Montana, the Niobrara formation in Colorado and other formations in Texas. We previously held interests located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana. However, we sold these non-core interests in July 2019.
The following table sets forth information with respect to operated wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.
The following table presents activity by operating area for the year ended December 31, 2019:
Turned to Sales
Turned to Sales
Utica Shale (1)
Of the 16 gross wells we drilled in 2019, six were completed as producing wells and 10 were in various stages of completion as of December 31, 2019.
Of the 10 gross wells we drilled in 2019, five were completed as producing wells, four were in various stages of completion and one was being drilled as of December 31, 2019.
The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the total gross and net developed and undeveloped acres as of December 31, 2019.
Most of our leases have a three- to five-year primary term, many of which include options to extend the primary term. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations and drilling to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2019
Years Ending December 31:
Held by production or operations
Oil, Natural Gas and NGL Reserves
The tables below set forth information as of December 31, 2019, with respect to our estimated proved reserves, the associated estimated future net revenue, the PV-10 and the standardized measure of discounted future net cash flows (“standardized measure”). None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.
Present value of estimated future net revenue (PV-10)(2)
Utica and SCOOP accounted for approximately 71% and 29%, respectively, of our estimated proved reserves by volume as of December 31, 2019.
Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2019, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2019. The prices used in our PV-10 measure were $55.85 per barrel and $2.58 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2019. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense. There was no effect of estimated future income tax expense as of December 31, 2019, primarily as a result of significant net operating loss carryforwards that can be used to offset income taxes on future taxable income.
Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.
Grizzly had no proved reserves as of December 31, 2019. For further discussion of our interest in Grizzly, see “Our Equity Investments” below.
Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year.
Changes in Proved Reserves during 2019.
The following table summarizes the changes in our estimated proved reserves during 2019 (in Bcfe):
Sales of oil and natural gas reserves in place. These are revisions to proved reserves resulting from the divestiture of minerals in place during a period. During 2019, we sold approximately 76.8 Bcfe of proved oil and natural gas reserves through various sales of our Southern Louisiana assets, non-operated interests in our Utica assets and overriding royalty interests in North Dakota.
Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 1.1 Tcfe of proved reserves were primarily attributable to the continued development of our Utica Shale and SCOOP acreage. We added 72 drilling locations in our Utica acreage for 793.5 Bcfe and 37 drilling locations in our SCOOP acreage for 302.9 Bcfe. This change reflects our ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.
Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs.
We experienced total downward revisions of 733.8 Bcfe in estimated proved reserves, of which 347.2 Bcfe was a result of the exclusion of nine PUD locations in our Utica field and 22 PUD locations in our SCOOP field when changes in our schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects our commitment to capital discipline and funding future activities within cash flow.
An additional 296.4 Bcfe in downward revisions was the result of commodity price changes. Commodity prices experienced volatility throughout 2019 and the 12-month average price for natural gas decreased from $3.10 per MMBtu for 2018 to $2.58 per MMBtu for 2019, the 12-month average price for NGL decreased from $32.02 per barrel for 2018 to $21.25 per barrel for 2019, and the 12-month average price for crude oil decreased from $65.56 per barrel for 2018 to $55.85 per barrel for 2019.
We also experienced downward revisions of 90.2 Bcfe from a combination of working interest changes, optimization of our well design in the current commodity price environment and well performance.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2019, 2018 and 2017 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information, in Note 19 of the notes to our consolidated financial statements included in this report.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2019, our proved undeveloped reserves totaled 10 MMbbl of oil, 2,291 Bcf of natural gas and 32 MMbbl of NGL, for a total of 2,544 Bcfe. Approximately 70% and 30% of our PUD reserves at year-end 2019 were located in Utica and SCOOP, respectively. PUDs will be converted from undeveloped to developed as the applicable wells commence production or there are no material incremental completion capital expenditures associated with such proved developed reserves.
We record PUD reserves only after a development plan has been approved by our senior management and board of directors to complete the associated development drilling within five years from the time of initial booking. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2019 (in Bcfe):
Proved Undeveloped Reserves, December 31, 2018
Sales of oil and natural gas reserves in place
Extensions and discoveries
Conversion to proved developed reserves
Revisions of prior reserve estimates
Proved Undeveloped Reserves, December 31, 2019
Sales of oil and natural gas reserves in place. During 2019, we sold approximately 68.8 Bcfe of proved undeveloped oil and natural gas reserves associated with various non-operated interests, the majority of which were in our Utica field.
Extensions and discoveries. Our extensions of approximately 1.1 Tcfe were primarily attributed to the addition of 72 PUD drilling locations in the Utica field and 37 PUD drilling locations in the SCOOP field as a result of our current development plan that refocused some activity within our existing fields. This change reflects our ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.
Conversion to proved developed reserves. Our 2019 development activities resulted in the conversion of approximately 654.0 Bcfe into proved developed producing reserves, attributable to 49 PUD locations in the Utica field and 12 PUD locations in the SCOOP field. These 61 PUDs represent a conversion rate of 20% for 2019.
Revision of prior reserve estimates. We experienced proved undeveloped downward revisions of 347.2 Bcfe from the exclusion of 9 PUD locations in our Utica field and 22 PUD locations in our SCOOP field due to the SEC five-year development rule. The development plan change, as approved by our senior management and Board of Directors, reflects our commitment to capital discipline and funding future activities within cash flow. We also experienced 146.8 Bcfe of downward revisions as a result of commodity price changes. These downward revisions were partially offset by positive revisions of 54.8 Bcfe in estimated proved reserves from a combination of well performance, changes in ownership interest and development well design changes.
Costs incurred relating to the development of PUDs were approximately $353.1 million in 2019.
All PUD drilling locations included in our 2019 reserve report are scheduled to be drilled within five years of initial booking.
As of December 31, 2019, 1% of our total proved reserves were classified as proved developed non-producing.
Reserve estimates at December 31, 2019 and December 31, 2018 were prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for all of our operating areas. Reserve estimates at December 31, 2017 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio, the SCOOP Woodford and SCOOP Springer plays in Oklahoma and our WCBB and Hackberry fields. Our personnel prepared reserve estimates with respect to our Niobrara field as well as our overriding royalty and non-operated interests at December 31, 2017.
NSAI is an independent petroleum engineering firm. A copy of the summary reserve reports is included as Exhibit 99.1 to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI, our independent reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Utica Shale, SCOOP, WCBB and Hackberry fields. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data,
commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 20 years of reservoir and operations experience. In addition, our geophysical staff has approximately 100 years combined industry experience and our reservoir staff has approximately 40 years combined experience.
Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us;
verification of property ownership by our land department;
preparation of reserve estimates by NSAI in coordination with our experienced reservoir engineers;
direct reporting responsibilities by our reservoir engineering department to our Chief Operating Officer;
review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
provision of quarterly updates to our board of directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves;
annual review by our board of directors of our year-end reserve report and year-over-year changes in our proved reserves, as well as any changes to our previously adopted development plans;
annual review and approval by our senior management and our board of directors of a multi-year development plan;
annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments; and
annual review by our board of directors of changes in our previously approved development plan made by senior management and technical staff during the year, including the substitution, removal or deferral of PUD locations.
As noted above, our December 31, 2019 proved reserves were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December 2019 of $55.85 per barrel and $2.58 per MMBtu. Holding production and development costs constant, if SEC pricing were $61.44 per barrel and $2.84 per MMBtu, or a 10% increase, this would have resulted in an increase of 69.6 Bcfe of our total proved reserves and a $0.7 billion increase in PV-10 value at December 31, 2019. Holding production and development costs constant, if SEC pricing were $50.27 per barrel and $2.32 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 106.5 Bcfe of our total proved reserves and a $0.7 billion decrease in PV-10 value at December 31, 2019.
Production, Prices and Production Costs
The following table presents our production volumes in our core operating areas during the periods indicated:
The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2019:
Year Ended December 31,
Natural gas (MMcf)
Average Sales Price Without the Impact of Derivatives:
Natural gas ($/Mcf)
Average Production Costs ($/Mcfe)
Year Ended December 31,
Natural gas (MMcf)
Average Sales Price Without the Impact of Derivatives:
Natural gas ($/Mcf)
Average Production Costs ($/Mcfe)
We acquired our SCOOP assets through an acquisition completed on February 17, 2017. See Note 2 in the notes to our consolidated financial statements for additional discussion of this acquisition.
Our Equity Investments
Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2019, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced commercial production from its Algar Lake Phase 1 steam-assisted gravity drainage ("SAGD") oil sand project during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen production. In April 2015, Grizzly made the decision to suspend operations at its Algar Lake facility due to the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as it assesses future plans for the facility. Grizzly also owns the May River property comprising approximately 47,000 acres prospective for oil sands development. An initial 12,000 barrel per day development application covering the eastern portion of the May River lease has been deemed complete from the Alberta Energy Regulator and received final approval in December 2019. If pursued, this project could begin production as early as 2023. A 2-D seismic program covering approximately 83 kilometers has been completed to more fully define the resource over the remaining lease beyond the development application area. In 2017, Grizzly advanced plans for cold heavy oil sands production ("CHOPS") at its Cadotte property in Peace River. However, plans for development are dependent on stabilized commodity prices. Grizzly continues to advance rail marketing strategies to ensure consistent and flexible access to
premium markets for its future production. Grizzly is also advancing a project to utilize its Windell truck to rail terminal located near Conklin, Alberta, for movement of liquefied petroleum gas ("LPG") into the oil sands area for use in Thermal applications by SAGD producers. We elected to cease funding capital calls in 2019, and we have no obligation to fund any of the projects Grizzly is pursuing. Failure to fund capital calls may lead to dilution of our equity ownership interest.
Mammoth Energy. In connection with Mammoth Energy's initial public offering ("IPO") in October 2016, we received 9,150,000 shares of Mammoth Energy common stock in return for our contribution to Mammoth Energy of our 30.5% interest in Mammoth Energy Partners LLC. In June 2017, we received an additional 2,000,000 shares of Mammoth Energy common stock in connection with our contribution of all of our equity interests in three other entities to Mammoth Energy. We sold 76,250 shares of our Mammoth Energy common stock in the IPO and an additional 1,354,574 shares in a subsequent underwritten public offering in 2018. As of December 31, 2019, we owned 9,829,548 shares, or approximately 21.8%, of Mammoth Energy’s outstanding common stock.
See Note 4 of the notes to our consolidated financial statements included elsewhere in this report for additional information regarding these and our other equity investments.
The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating of commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for Gulfport’s interest and other interest owners in Gulfport-operated wells. In addition, there are a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our pipeline delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets.
Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority being shorter term in nature. We have entered into long-term gathering, processing and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our commitments.
For the year ended December 31, 2019, sales to Morgan Stanley Capitalaccounted for approximately 14% of our total natural gas, oil and NGL revenues, before the effects of hedging. For the year ended December 31, 2018, sales to BP Energy Company ("BP") and ECO-Energy accounted for approximately 17% and 10%, respectively, of our total natural gas, oil and NGL revenues, before the effects of hedging. For the year ended December 31, 2017, sales to BP accounted for approximately 40% of our total natural gas, oil and NGL revenues, before the effects of hedging.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include renewable sources such as wind or solar energy in addition to coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Title to Oil and Natural Gas Properties
It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations.
Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
reporting of workplace injuries and illnesses;
industrial hygiene monitoring;
worker protection and workplace safety;
approval or permits to drill and to conduct operations;
provision of financial assurances (such as bonds) covering drilling and well operations;
calculation and disbursement of royalty payments and production taxes;
seismic operations and data;
location, drilling, cementing and casing of wells;
well design and construction of pad and equipment;
construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
method of completing wells;
well production and operations, including processing and gathering systems;
emergency response, contingency plans and spill prevention plans;
air emissions and fluid discharges;
use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
plugging and abandoning of wells; and
transportation of production.
Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters.
Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural
gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.
Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
We maintain a control of well insurance policy with a $25 million single well limit and a $35 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $101 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean up services during each of 2019 and 2018 were immaterial. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. We pay these companies a retainer plus additional amounts when they provide us with clean up services.
David M. Wood, Chief Executive Officer, President and Director
David M. Wood, 62,has served as the Chief Executive Officer and President of the Company, and as a member of our board of directors, since December 2018. Prior to joining the Company, Mr. Wood served as the Chief Executive Officer and Chairman of the Board of Directors of Arsenal Resources LLC, which we refer to as Arsenal, a West Virginia focused natural gas producer and portfolio company of First Reserve Corporation ("First Reserve"), an energy-focused private equity firm, where he most recently served as Chairman of its board of directors and previously held the role of the Chief Executive Officer. Prior to his tenure at Arsenal, Mr. Wood served as a Senior Advisor to First Reserve from 2013 to 2016, serving on several of its portfolio company boards. Prior to his position at First Reserve, Mr. Wood spent more than 17 years at Murphy Oil Corporation (NYSE: MUR) ("Murphy Oil"), a global oil and natural gas exploration and production company, where he served as Chief Executive Officer, President and a member of the board of directors from 2009 to 2012. From 1980 to 1994, Mr. Wood held various senior positions with Ashland Exploration and Production, an oil and natural gas exploration and production company. Mr. Wood began his career as a well-site geologist in Saudi Arabia. Mr. Wood has served on the board of directors of Lilis Energy, Inc. (NYSE: LLEX), an exploration and development company operating in the Delaware Basin since June 2018. Mr. Wood also served on the board of directors of the general partner of Crestwood Equity Partners LP (NYSE: CEQP) and its wholly-owned subsidiary, Crestwood Midstream Partners LP, an owner and operator of crude oil and natural gas midstream assets. Mr. Wood also served on the board of directors of several private oil and natural gas companies, including Deep Gulf Energy LP (prior to its acquisition by Kosmos Energy Ltd.) and Berkana Energy Corp. (when it was majority owned by Murphy Oil). Mr. Wood previously served on the board of directors and as an executive committee member of the American Petroleum Institute. He was also a member of the National Petroleum Council and is a member of the Society of Exploration Geophysicists. Mr. Wood holds a B.S. in Geology from the University of Nottingham in England and completed Harvard University’s Advanced Management Program.
Quentin R. Hicks, Executive Vice President and Chief Financial Officer
Quentin R. Hicks, 45,has served as the Executive Vice President and Chief Financial Officer of the Company since August 2019. Prior to joining the Company, Mr. Hicks served as the Executive Vice President and Chief Financial Officer of Halcón Resources Corporation (“Halcón”), a position he held since March 2019, having previously served as Executive Vice President, Finance, Capital Markets and Investor Relations of Halcón since January 2018. Prior to that, Mr. Hicks held various roles at Halcón focused primarily on finance and investor relations. Prior to Halcón, Mr. Hicks worked for GeoResources Inc., where he served as Director of Acquisitions and Financial Planning from 2011 to 2012. From 2004 to 2011, he worked in investment banking with Bear Stearns, Sanders Morris Harris and Madison Williams, where he was a Director in their energy investment banking practice. Prior to that, Mr. Hicks worked as Manager of Financial Reporting for Continental Airlines. Mr. Hicks began his career in 1998 working as an auditor for Ernst and Young LLP. Mr. Hicks graduated from Texas A&M University with a Bachelor of Business Administration and a Master of Science degree in Accounting. In addition, Mr. Hicks holds a Master of Business Administration degree in Finance from Vanderbilt University and also holds a Certified Public Accountant license from the State of Texas.
Donnie G. Moore, Executive Vice President and Chief Operating Officer
Donnie G. Moore, 55, has served as Executive Vice President and Chief Operating Officer of the Company since January 2018. He also served as Interim Chief Executive Officer of the Company from October 29, 2018, the date our former Chief Executive Officer and President left the Company, to December 18, 2018, the date of the appointment of Mr. Wood as our new Chief Executive Officer and President. From 2007 until December 2017, Mr. Moore worked at Noble Energy, Inc. ("Noble"), where he most recently served as Vice President of Noble’s Texas operations for its Eagle Ford and Delaware Basin assets. Prior to that, Mr. Moore held various leadership roles at Noble including Vice President of the Marcellus Business Unit, Manager for Operations of the Wattenberg/DJ Business Unit, Manager of Operations for the Gunflint discovery in the Deepwater Gulf of Mexico and Development Manager for Noble’s Mid-Continent and Gulf Coast positions. From 1989 until 2007, Mr. Moore served in a variety of roles with ARCO Oil and Gas Company, Vastar Resources, Inc. and BP America. Mr. Moore holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.
Patrick K. Craine, Executive Vice President, General Counsel and Corporate Secretary
Patrick K. Craine, 47, has served as Executive Vice President, General Counsel and Corporate Secretary of the Company since May 2019. Mr. Craine has over 20 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. He joined Gulfport from Chesapeake Energy Corporation (NYSE: CHK) ("Chesapeake"), where he served as Deputy General Counsel – Chief Risk and Compliance Officer from 2013 until 2019. Prior to joining Chesapeake, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces.
Michael J. Sluiter, Senior Vice President of Reservoir Engineering
Michael J. Sluiter, 47, has served as Senior Vice President of Reservoir Engineering of the Company since December 2018. Mr. Sluiter joined the Company from Noble Energy, Inc., where he held various engineering and leadership positions from March 2007 to November 2018, including, most recently, the Permian Basin Business Unit Manager. Prior to, Noble Mr. Sluiter worked for Santos Australia and Santos USA from February 2000 to March 2007, and started his career as a wireline field services engineer for Schlumberger in Thailand. He has over 18 years combined of experience in unconventional resource development, reservoir engineering, subsurface development, business development and acquisitions. Mr. Sluiter holds a Bachelor of Science degree in Chemical Engineering from the University of Sydney, Australia.
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.
Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, cash flows, profitability, future rate of growth, production and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for natural gas and, to a lesser extent, oil and NGL. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas, oil and NGL prices may result in ceiling test write-downs of our oil and natural gas properties.
Historically, the markets for natural gas, oil and NGL have been volatile, and they are likely to continue to be volatile. For example, during 2018, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. As of February 14, 2020, the WTI price was $52.03 per barrel and the Henry Hub spot market price of natural gas was $1.93 per MMBtu.
Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;
the level of prices, and expectations about future prices, of oil and natural gas;
changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the expected rates of declining current production;
changes in the level of consumer and industrial demand;
the price and availability of alternative fuels;
technological advances affecting energy consumption;
risks associated with operating drilling rigs;
the effectiveness of worldwide conservation measures;
the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
U.S. exports of oil, natural gas, liquefied natural gas and NGL;
the price and level of foreign imports;
the nature and extent of domestic and foreign governmental regulations and taxes;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and Russia;
acts of terrorism; and
domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. As of February 27, 2020, including January and February derivative contracts that have settled, approximately 50% of our forecasted 2020 natural gas, oil and NGL production revenue was hedged, including 52% and 80% of our forecasted 2020 natural gas and oil production, at average prices of $2.86 per Mcf and $59.82 per Bbl, respectively. Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2020 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2021 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.
We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.
As of December 31, 2019, we had approximately $2.0 billion in principal amount of debt outstanding, primarily attributable to our senior notes. We also had $120.0 million in borrowings outstanding under our revolving credit facility and our borrowing base availability was $636.4 million after giving effect to an aggregate of $243.6 million of letters of credit.
Our outstanding indebtedness could have important consequences to you, including the following:
our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including their restrictive covenants,
could result in a default under our revolving credit facility or the indentures governing our senior notes;
the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;
our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;
we must use a substantial portion of our cash flow from operations to pay interest on our senior notes and our other indebtedness, which will reduce the funds available to us for operations and other purposes;
our level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt;
our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;
our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and
we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations and prospects.
Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. If our borrowing base under our revolving credit facility decreases as a result of lower prices of natural gas, oil or NGL, operating difficulties, declines in reserves or for any other reason, our liquidity and ability to conduct additional exploration and development activities may be limited. To the extent that the value of the collateral pledged under our revolving credit facility declines as a result of lower oil and natural gas prices, asset dispositions or otherwise, we may be required to pledge additional collateral to maintain the current availability of the commitments thereunder, and we cannot assure you that we will be able to maintain a sufficiently high valuation to maintain the current borrowing base. In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or litigation. Any of the above risks could materially adversely affect our business, financial condition, cash flows and results of operations.
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level and industry conditions.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Low commodity prices have caused and may continue to cause lenders to increase the interest rates under our revolving credit facility, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and reduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. Additionally, challenges in the economy have led and could further lead to reductions in the demand for natural gas, oil and NGL, or further reductions in the prices of natural gas, oil and NGL, which could have a negative impact on our financial position, results of operations and cash flows.
If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.
Our earnings and cash flow could vary significantly from year to year due to the volatility of hydrocarbon commodity prices. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments or to make necessary capital expenditures. A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operations and service our debt. Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to our business, many of which are beyond our control. Any cash flow insufficiency would have a material adverse impact on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.
If we do not generate sufficient cash flow from operations to service our outstanding indebtedness, or if future borrowings are not available to us in an amount sufficient to enable us to pay or refinance our indebtedness, we may be required to undertake various alternative financing plans, which may include:
•refinancing or restructuring all or a portion of our debt;
•seeking alternative financing or additional capital investment;
•selling strategic assets;
•reducing or delaying capital investments; or
•revising or delaying our strategic plans.
We cannot assure you that we would be able to implement any alternative financing plans, if necessary, on commercially reasonable terms or at all,or that any such alternative financing plans would allow us to meet our debt obligations. If we are unable to generate sufficient cash flow to satisfy our debt obligations or to obtain necessary and sufficient alternative financing, our business, financial condition, results of operations, cash flows and liquidity could be materially and adversely affected. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could significantly harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our revolving credit facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, our revolving credit facility and the indentures governing our senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair. If the amounts outstanding under our revolving credit facility or any of our other significant indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders or to our other debt holders. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
Restrictive covenants in our revolving credit facility and the indentures governing our senior notes could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Our revolving credit facility and the indentures governing our senior notes impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things
incur or guarantee additional indebtedness;
make certain investments;
declare or pay dividends or make distributions on our capital stock;
prepay subordinated indebtedness;
sell assets, including capital stock of restricted subsidiaries;
agree to payment restrictions affecting our restricted subsidiaries;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
enter into transactions with our affiliates;
engage in business other than the oil and gas business; and
designate certain of our subsidiaries as unrestricted subsidiaries.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indentures governing our senior notes. The restrictions contained in the covenants could:
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan;
adversely affect our ability to finance our operations, enter into acquisitions or divestitures to engage in other business activities that would be in our interest; or
withstand a continuing future downturn in our business.
Also, our revolving credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Specifically, our revolving credit facility requires us to maintain a ratio of net funded debt to EBITDAX at the end of each fiscal quarter for a twelve-month period of not greater than 4.00 to 1.00, and a ratio of EBITDAX to interest expense at the end of each fiscal quarter for a twelve-month period of not less than 3.00 to 1.00. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in natural gas, oil and NGL prices, or a prolonged period of low natural gas, oil and NGL prices could eventually result in our failing to meet one or more of the financial covenants under our revolving credit facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.
A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our Notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.
We could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Any significant reduction in our borrowing base under our revolving credit facility as a result of periodic borrowing base
redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.
Availability under our revolving credit facility is currently subject to a borrowing base of $1.2 billion, with an elected commitment of $1.0 billion. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2019, we had $120.0 million in borrowings and $243.6 million of letters of credit outstanding under our revolving credit facility. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indentures governing our senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2019, our borrowing base under our revolving credit facility was set at $1.2 billion, with an elected commitment of $1.0 billion, and we had $120.0 million in borrowings under this facility. Total funds available for borrowing under our revolving credit facility as of December 31, 2019, after giving effect to $243.6 million of outstanding letters of credit, were $636.4 million. In addition, the indentures governing our Notes allow us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indentures governing our senior notes also allow us to incur certain other additional secured debt and allow us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to our senior notes. If new debt or other liabilities are added to our current debt levels, the related risks that we now face could intensify.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. Our revolving credit facility is structured under floating rate terms. As such, our interest expense is sensitive to fluctuations in the London Interbank Offered Rate. At December 31, 2019, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.30%. A 1% increase in the average interest rate would have increased our interest expense by approximately $1.2 million based on outstanding borrowings under our revolving credit facility throughout the year ended December 31, 2019. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our revolving credit facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. As of December 31, 2019, we did not hedge our interest rate risk.
Changes in the method of determining the London Interbank Offered Rate, or the replacement of the London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under our revolving credit facility may bear interest at rates based on the London Interbank Offered Rate (“LIBOR”). On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Our revolving credit facility provides for a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.
Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proved oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting natural gas to barrels at the ratio of six Mcf of natural gas to one barrel of oil.
Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the unweighted arithmetic average of the closing prices on the first day of each month for the 12-month period ending at the balance sheet date, adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can result in a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. As a result of the decline in commodity prices, we recorded a ceiling test impairment of $2.0 billion for the year ended December 31, 2019. If prices of natural gas, oil and natural gas liquids continue to decrease, we will be required to further write down the value of our oil and natural gas properties. Future non-cash asset impairments could negatively affect our results of operations.
Our development, acquisition and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. For example, we currently estimate our drilling and completions capital expenditures for 2020 to be in the range of $265 million to $285 million and an additional $20 million to $25 million for leasehold expenditures, primarily lease extensions and infill leasing within our Utica Shale and Scoop development plans.
Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity and debt securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the volume of oil and natural gas we are able to produce from existing wells;
the prices at which oil and natural gas are sold;
our ability to acquire, locate and produce economically new reserves; and
our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2020 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we
have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2019, approximately 56.2% of our total estimated proved reserves were proved undeveloped reserves ("PUDs") and may not be ultimately developed or produced. Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2019 present value is based on a $2.58 per MMBtu of gas price and a $55.85 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
Actual future net revenues from our oil and natural gas properties will also be affected by factors such as:
•actual prices we receive for oil and natural gas;
•supply of and demand for oil and natural gas; and
•changes in governmental regulations or taxation.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We acquire significant amounts of unproven properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGL, costs associated with producing natural gas, oil and NGL and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
If production from our Utica Shale or SCOOP acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our firm commitment delivery obligations under our firm transportation contracts, which will result in fees and may have a material adverse effect on our operations.
As of December 31, 2019, we had entered into firm transportation contracts to deliver approximately 1,205,000 MMBtu to 1,505,000 MMBtu per day for 2020 and 2021. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. If production from our Utica Shale or SCOOP acreage decreases due to decreased developmental activities, taking into consideration the current low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the development activities we employ, such as offset drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of offset drilling, adjacent wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing.
The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas, such as our SCOOP play in Oklahoma. The area was historically developed by vertical wells drilled through multiple stacked reservoirs and recent development has focused on the Woodford formation; however, development in the Sycamore and Springer formations has been limited. As emerging formations, our drilling results in this area are more uncertain than drilling results in areas that are more developed and have been producing for a longer period of time. Since limited production history from horizontal wells in the SCOOP Sycamore and Springer formations exists over our acreage position, it is difficult to predict our future drilling results.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be realized.
There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially.
Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to
assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly's lands cannot be determined at this time.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Approximately 20% of our Utica Shale undeveloped acreage that is subject to expiration will be subject to expiration in 2020, with 17% of such acreage expiring in 2021, 22% in 2022 and 41% thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. Although 97% of our SCOOP acreage is held by existing production from both vertical and horizontal wells, the remaining acreage is subject to expiration. Of the remaining 3% of our SCOOP acreage not held by production, 59% will be be subject to expiration in 2020, 17% in 2021, 7% in 2022 and 17% thereafter. During the year ended December 31, 2019, leases representing 66% of our total Niobrara Formation undeveloped acreage as of December 31, 2018 expired due to failure to establish production. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.
We are defending against claims by royalty owners alleging, among other things, that we underpaid royalty owners. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.
In addition, there is an ongoing SEC investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002. The outcome of any pending or future litigation or governmental regulatory matter is uncertain and may
adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past three years, and such expenses may continue to be significant in the future. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing our business.
Oil and natural gas operations are uncertain and involve substantial costs and risks. Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our oil and natural gas operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, natural gas and NGL can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. For the 16% of our daily production volumes from properties which we did not serve as operator as of December 31, 2019, we are dependent on the operator for operational and regulatory compliance. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
loss of drilling fluid circulation;
equipment failures or accidents;
fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;
risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives;
adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;
issues with title or in receiving governmental permits or approvals;
restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us;
restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
shortages or delays in the availability of services or delivery of equipment; and
unexpected or unforeseen changes in regulatory policy, and political or public opinions.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities.
While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. We may not be able to secure additional insurance or bonding
that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including:
the timing and amount of capital expenditures;
the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
the operator's expertise and financial resources;
approval of other participants in drilling wells;
selection of technology; and
the rate of production of the reserves.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
Recent decisions by the Ohio Supreme Court interpreting the Ohio Dormant Mineral Act relating to preservation of mineral rights by surface owners could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expenses, subject us to payment of additional royalties or result in the loss of some of our leasehold acreage in Ohio.
On September 15, 2016, the Ohio Supreme Court issued a series of decisions relating to the Ohio Dormant Mineral Act, which we refer to as the ODMA. In the lead case, Corban v. Chesapeake Exploration L.L.C., the court concluded that the 1989 version of the ODMA did not transfer ownership of dormant mineral rights automatically, by operation of law. Instead, prior to 2006, surface owners were required to bring a quiet title action to establish abandonment of mineral rights. After June 30, 2006, (the effective date of the 2006 version of the ODMA), surface owners are required to follow the statutory notice and recording procedures enacted in 2006. We have assessed the impact of these recent Ohio Supreme Court decisions on our operations in Ohio where the majority of our acreage and our producing properties are located and have taken steps to mitigate any potential risks identified as a result of our assessment. However, the Ohio Supreme Court decisions could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expense, subject us to payment of additional royalties or result in the loss of some of our leasehold acreage in Ohio, any of which could have an adverse effect on our results of operations and financial condition.
We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or
In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.
Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. PHMSA has not yet issued the final rule. In October 2019, three final rules making up the “Gas Mega Rule” - one establishing procedures to implement the expanded emergency order enforcement authority; the second, concerning gas transmission, extending the requirement to conduct integrity assessments beyond HCAs to pipelines in Moderate Consequence Areas (“MCAs”); and the third, concerning hazardous liquids, extending the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines and updating reporting and inspection requirements - were finalized. The cost of these requirements or other potential new or amended regulations could be significant, and any such costs incurred by our midstream service providers could result in increased midstream gathering and processing expenses for us. Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations.
Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the Oklahoma Corporation Commission (OCC) issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. Three states (New York, Maryland and Vermont) have banned the use of high-volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. A decision is pending.
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S.
federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations or taxes on greenhouse gas emissions. Several states where we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. A carbon tax could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells.
In our Utica operations, we attempt to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active. While our objective is to recycle 100% of all produced water, we do inject water into third party commercially operated disposal wells in line with all state and federal mandated practices and cease produced water recycle whenever fracture stimulation operations are idle. In the state of Ohio, all water used during drilling operations is disposed of through injection into third party salt water disposal wells regulated by applicable state agencies.
In our SCOOP operations, Oklahoma regulations allow for the storage of produced water in permitted lined impoundments. These storage impoundments allowed us to recycle approximately 75% of our produced water in 2019 from all of our producing wells. All of our wells completed in 2019 in our SCOOP asset were completed with recycled produced water from these impoundments with minimal use of local freshwater sources. These recycling facilities allowed us to dramatically reduce the amount of produced water that had to be injected into state regulated commercial disposal wells, and decreased our reliance of local freshwater sources required for our completions operations.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids
Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, legislative proposals have been introduced in the U.S. Congress in the past that, if enacted, would (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) repeal the percentage depletion allowance for oil and natural gas properties, and (iii) extend the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. In addition, at the state level, legislative changes imposing increased taxes on oil and gas production have periodically been considered in Ohio and Oklahoma. These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.
Substantially all of our producing properties are located in Eastern Ohio and Oklahoma, making us vulnerable to risks associated with operating in these regions.
Our largest fields by production are located in Eastern Ohio and Oklahoma. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes, tornados or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.
The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and, due to our debt levels and other factors, may have greater access to the capital and credit markets. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.
The largest purchaser of our oil and natural gas during the year ended December 31, 2019 accounted for approximately 14% of our total natural gas, oil and NGL revenues. If this purchaser or one or more other significant purchasers, are unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.
Risks related to potential acquisitions or dispositions may adversely affect our business. Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.
From time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments, including equity investments and joint ventures. These transactions involve various inherent risks, such as changes in prevailing market conditions, our ability to obtain the necessary regulatory approvals, the timing of and conditions that may be imposed on us by regulators and our ability to achieve benefits anticipated to result from the transactions.