10-K 1 upl-10k_20191231.htm 10-K upl-10k_20191231.htm

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 UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to

Commission file number 001-33614

 

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

 

 

 

 

Yukon, Canada

 

N/A

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. employer identification number)

 

 

116 Inverness Drive East, Suite 400
Englewood, Colorado

 

80112

(Address of principal executive offices)

 

(Zip code)

(303) 708-9740

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act: None.

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) during the preceding 12 months (or for 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

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 for 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 Act).    YES         NO 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $28,438,541 as of June 28, 2019 (based on the last reported sales price of $0.18 of such stock on the NASDAQ on such date).

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  YES         NO 

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of March 31, 2020 was 198,303,021.

Documents incorporated by reference:

Portions of the registrant’s definitive proxy statement relating to its 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2019, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Form 10-K. 

 

 


Table of Contents

 

 

TABLE OF CONTENTS

 

 

 

 

  

Page

 

 

PART I

  

 

 

 

  

 

 

  

Item 1.

 

Business

  

 

3

  

Item 1A.

 

Risk Factors

  

 

13

  

Item 1B.

 

Unresolved Staff Comments

  

 

29

  

Item 2.

 

Properties

  

 

29

  

Item 3.

 

Legal Proceedings

  

 

36

  

Item 4.

 

Mine Safety Disclosures

  

 

36

  

 

PART II

  

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  

 

37

 

Item 6.

 

Selected Financial Data

  

 

38

 

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

 

39

  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

 

57

  

Item 8.

 

Financial Statements and Supplementary Data

  

 

57

  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

  

 

96

  

Item 9A.

 

Controls and Procedures

  

 

96

  

Item 9B.

 

Other Information

  

 

96

  

 

PART III

  

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

 

97

  

Item 11.

 

Executive Compensation

  

 

97

  

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  

 

97

  

Item 13.

 

Certain Relationships, Related Transactions and Director Independence

  

 

97

  

Item 14.

 

Principal Accounting Fees and Services

  

 

97

  

 

PART IV

  

Item 15.

 

Exhibits, Financial Statement Schedules

  

 

98

  

 

 

Signatures

  

 

102

  

 

 

Certain Definitions

 

 

103

 

 

 

 


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PART I

Item 1.

Business.

General

Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, or “us”) is an independent exploration and production company focused on developing and producing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basis of southwest Wyoming. The Company was incorporated in 1979, under the laws of the Province of British Columbia, Canada. Ultra remains a Canadian company, and since March 2000, has operated under the laws of Yukon, Canada pursuant to Section 190 of the Yukon Business Corporations Act.

The Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to such reports and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge to the public on the Company’s website at www.ultrapetroleum.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. You may also request a copy of these filings at no cost by making written or telephone requests for copies to Ultra Petroleum Corp., Investor Relations, 116 Inverness Drive East, Suite 400, Englewood, CO 80112, (303) 708-9740, ext. 9898. The Securities and Exchange Commission (“SEC”) maintains an internet site that contains reports, proxy and information statements, and other information regarding the Company. The SEC’s website address is www.sec.gov.

Oil and Gas Properties Overview

Principal Operating Area

The Company conducts operations exclusively in the United States.  Its operations in southwest Wyoming have historically focused on producing and developing its long-life natural gas reserves in a tight gas sand trend located in the Green River Basin. The Company targets sands of the upper Cretaceous Lance Pool in the Pinedale and Jonah fields. The Lance Pool, as administered by the Wyoming Oil and Gas Conservation Commission (“WOGCC”), includes sands of the Lance formation at depths between approximately 8,000 and 12,000 feet and the Mesaverde formation at depths between approximately 12,000 and 14,000 feet. As of December 31, 2019, Ultra owned interests in approximately 117,000 gross (83,000 net) acres in Wyoming covering approximately 190 square miles.  Following the sale of the Company’s Pennsylvania properties in late 2017 and Utah assets in late 2018, all oil and gas operations are now focused in the Pinedale and Jonah fields.

Mission and Strategy

Ultra’s mission and strategy is focused on disciplined capital allocation decisions, generating operating cash flows, reducing its indebtedness, and preserving future potential drilling inventory for more constructive natural gas prices.  The Company’s emphasis on these elements is critically relevant as the natural gas commodity price has eroded further over the course of 2019, and the forward strip pricing remains at depressed levels.  Given Ultra’s focus on profitability and generating operating cash flows to repay its indebtedness, the Company elected to suspend drilling operations in the third quarter of 2019, as the investment returns were unattractive in the current commodity price environment.  The Company determined it is in the best interest of its stakeholders to retain core personnel necessary in order to operate its prolific asset base safely, efficiently, and profitably; to ensure necessary regulatory and environmental compliance; to continue to fulfill its obligations as a public reporting company; to continue to dedicate appropriate resources to studying the underlying geologic and subsurface in order to maximize the value of the Pinedale and Jonah fields; and to prepare to resume a drilling program with much of the historical knowledge and intellectual property developed over many years by Ultra personnel.  

Due to the suspension of the drilling program, the Company has no estimated proved undeveloped (“PUD”) reserves as of December 31, 2019, with respect to its properties because it has elected not to drill new wells in the current commodity price environment. Additionally, as noted below, the Company has a $5 million limitation of capital expenditures per quarter as set forth in the Fifth Amendment to the Credit Agreement (as defined below). The Company previously reported estimated PUD reserves in annual SEC filings, and, if in the future we can satisfy the reasonable certainty criteria as prescribed under the SEC requirements, we could include PUD reserves in future filings.

Liability Management Activities. In 2019, Ultra continued its liability management activities. In the first quarter of 2019, the Company executed incremental note exchange transactions of $44.6 million of the 6.875% Senior Notes due 2022 (the “2022 Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of the Company, for $27.0 million of new 9.00% Cash / 2.00% PIK Senior Secured Second Lien Notes due July 2024 (the “Second Lien Notes”) (such transaction, the “Incremental Exchange”).  

The Company also attempted to exchange a portion of the outstanding 7.125% Senior Notes due 2025 (the “2025 Notes”) of Ultra Resource, for new 9.00% Cash / 2.50% PIK Senior Secured Third Lien Notes due 2024 of Ultra Resources, as allowed by the current Credit Agreement, Term Loan Agreement (as defined below) and Second Lien Indenture (as defined below).  The Company ultimately terminated this exchange offer in July 2019, as it determined the economic terms and the additional layer of secured indebtedness were not in the best interest of the Company.  

In February and March 2020, the Company entered into confidentiality agreements and commenced discussions with certain holders of the Company’s long-term debt and their legal and financial advisors.  The Company previously engaged with certain debtholders regarding

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potential out-of-court restructuring, but as previously disclosed on March 5, 2020, such negotiations are no longer occurring.  Negotiations and discussions with certain other debtholders and their advisors are now ongoing regarding a potential in-court restructuring, although as of the date of this filing no definitive agreements have been reached regarding any amendments, restructurings or other transactions relating to the Company’s indebtedness.

If an agreement is reached and the Company pursues a restructuring, it may be necessary for the Company to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act in order to implement an agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings.  The Company also may conclude that it is necessary to initiate proceedings under Chapter 11 of the United States Bankruptcy Code to implement a restructuring of its obligations even if it is unable to reach an agreement with its creditors and other relevant parties regarding the terms of such a restructuring.  In either case, such a proceeding could be commenced in the near term.

As discussed under Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, the Company believes it will require a significant restructuring of its balance sheet in order to continue as a going concern in the long term as a result of extremely challenging current market conditions.  The Company has based this belief on assumptions and estimates which are to some degree subjective and may vary considerably from actual results, and it could spend its available financial resources less or more rapidly than currently expected.

Strategic Alternatives. As announced in November 2019, the Company previously engaged Tudor, Pickering, Holt & Co. as an advisor to assist management and the Board of Directors in evaluating a range of strategic alternatives, including without limitation, a corporate sale, merger or other business combination, one or more strategic acquisitions or divestitures, or other transactions. The Company terminated this engagement in the first quarter of 2020, but may elect to reengage this advisor at a later date.

The Company continues to explore a number of other potential actions in order to address its liquidity and balance sheet issues, including, among other things, amendments and waivers.

There is no assurance that these initiatives will result in a transaction that is accretive to the per share value of the Company. The Company has not set a timetable for the evaluation process and is continuing to evaluate the opportunities to resume a capital program on a more diversified regional basis or to be a consolidator with other operators, subject to increasing commodity prices.

 

Commodity Price Volatility.  Beginning in March 2020, oil and natural gas commodity prices have experienced extreme volatility primarily attributable to decreased demand resulting from COVID and the actions of OPEC and other oil exporting nations. These events have limited our ability to execute on our business plan and adversely affected our business. Please see “Risk Factors-- Outbreaks of communicable diseases could adversely affect our business, financial condition and results of operations” and “--The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

Oil and Gas Development Portfolio.  Ultra seeks to maintain a portfolio of properties that provide long-term, profitable growth through development in areas that support sustainable, lower-risk, repeatable, high-return drilling projects.  The Company evaluates opportunities for the acquisition, exploration, and development of additional oil and natural gas properties that afford risk-adjusted returns in excess of or equal to its current set of investment alternatives.

Focus on Maximizing Value.  Ultra strives to maintain one of the lowest cost structures in the industry in terms of both producing and adding oil and natural gas reserves.  In 2019, the Company continued to focus on improving its drilling and production results using advanced technologies and detailed technical analysis of its properties, while maintaining its low-cost structure, adhering to industry and regulatory best practices, maintaining strict safety and environmental standards, and recruiting and retaining top talent within the Company.  This is evidenced by the Company’s low-cost operations, the improvement in well costs, and the advancement of lower-cost drilling processes that served to enhance investment returns in 2019.  

Credit Agreement Activity

Ultra Resources entered into a Credit Agreement (as amended, the “Credit Agreement”) as the borrower with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “RBL Lenders”), providing for a revolving credit facility (the “Revolving Credit Facility”) subject to a borrowing base redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (as defined below).

During 2019, the Company met all of its financial obligations, including debt service and interest obligations, and was in compliance with the requirements of its various debt instruments.  The Company proactively negotiated amendments to its Credit Agreement twice during 2019 which aligned with the stated goals of directing cash flows to reduce indebtedness. At December 31, 2019, the Company had a commitment of $200.0 million under its Revolving Credit Facility and a borrowing base of $1.175 billion, of which $64.7 million was outstanding. Additionally, the Company had $6.7 million of letters of credit outstanding. Availability under the Revolving Credit Facility is defined as the undrawn portion of the commitment, plus the unrestricted cash of the Company, and net of any outstanding letters of credit.

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On February 14, 2020, Ultra Resources entered into the Sixth Amendment to the Credit Agreement (the “Sixth Amendment”) with the RBL Administrative Agent and the RBL Lenders party thereto.  Pursuant to the Sixth Amendment and the spring 2020 redetermination, the Borrowing Base (as defined in the Credit Agreement) was reduced to $1.075 billion, with $100 million attributed to the Revolving Credit Facility, effective on April 1, 2020.  The Sixth Amendment also reduced the excess cash threshold to $15 million as part of the anti-cash hoarding provisions and established quarterly, rather than semi-annual, redeterminations of the borrowing base. The next borrowing base redetermination is scheduled to be completed on or before July 1, 2020.  

Given the potential for decreases in future commodity prices, the borrowing base level is subject to redetermination risk.  If the borrowing base or the commitment amount were redetermined below the levels of outstanding indebtedness associated with the Revolving Credit Facility and Term Loan Agreement, or if the commitment amount was inadequate to fund ongoing operations, the Company could potentially trigger mandatory repayment provisions of the Revolving Credit Facility or demands to reduce the Term Loan Agreement balance.  Given the overall credit metrics of the Company and the state of the debt markets, such a situation could result in the Company having an event of default under its debt obligations.

The report of the Company’s independent registered public accounting firm that accompanies its audited consolidated financial statements in this Annual Report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern.  As a result, the Company has reclassified all of its total outstanding debt as current.  Because the audit report prepared by the Company’s independent registered public accounting firm includes an explanatory paragraph expressing uncertainty as to its ability to continue as a going concern, the Company is in default under each of the Credit Agreement and Term Loan Agreement on April 14, 2020 when the Company delivers its financial statements to the lenders under the Credit Agreement. There is a 30-day grace period related to this covenant in the Credit Agreement. If the Company does not obtain a waiver or other suitable relief from the lenders under the Credit Agreement or the Term Loan Agreement before the expiration of the 30-day grace period, an event of default under each of the Credit Agreement and Term Loan Agreement would occur. As a result of the going concern qualification in the independent registered public accounting firm’s report to the December 31, 2019 financial statements,  the Company’s immediate liquidity is limited to cash as it will not have access to its Revolving Credit Facility beginning on April 15, 2020.  

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” for a description of the Revolving Credit Facility and other debt instruments.

2018 and 2017 Divestitures

The Company previously had operations in the Uinta Basin in Utah and in north central Pennsylvania.

During the third quarter of 2018, the Company completed the sale of its Utah assets for net cash proceeds of $69.3 million, including transaction fees of $0.6 million. The divested assets consisted primarily of oil and gas properties.  Prior to the sale, production from the Company’s Utah assets totaled approximately 420,000 Bbl of oil and 745,000 Mcf of natural gas in 2018.

During the fourth quarter of 2017, the Company divested its properties in the Pennsylvania Devonian aged Marcellus Shale, for net cash proceeds of approximately $115.0 million. Prior to the sale, production from the Pennsylvania assets totaled approximately 11.2 million Mcf of natural gas in 2017.

Exploration and Production

See Item 2. “Properties” for a description of our properties.

Green River Basin, Wyoming

During 2019, the Company completed and turned to sales 93 gross (77.6 net) vertical and 1 gross (0.9 net) horizontal wells operated by the Company and others in Wyoming and continued to improve its drilling and completion efficiency on its operated wells. Of these wells, the Company operated 71 gross (70.3 net) vertical wells and 1 gross (0.9 net) horizontal wells.  In line with the Company’s commitment to make its operations more efficient, the Company’s development was focused on vertical wells in 2019. The operated well costs for vertical wells declined since 2017 to $2.87 million per well during third quarter 2019 at which time the Company suspended its drilling operations. The decline of well costs in 2019 is a result of an increased success rate of the two-string drilling design over the year, as well as overall improvements in efficiencies and cost management throughout the year. Included in the well results was the successful completion of seven wells with the two-string design in third quarter 2019 at an average well cost of $2.65 million per well, highlighting improvement of the selection of the locations for this application in the Pinedale Field, as well as the knowledge gained over the course of the year as to the application of the techniques deployed.  The Company operates 92% of its production in the Pinedale field.  

During 2020, the Company plans to continue its focus on cash flow generation and reduction of indebtedness.  Development activity may occur if there is a sustained increase in the expected realized natural gas price and the Company amends it Credit Agreement to remove the limitation of capital investments to amounts below $5.0 million per quarter, which was implemented in connection with the Fifth Amendment to the Credit Agreement on September 16, 2019 (the “Fifth Amendment”).

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Marketing and Pricing

Overview

During the year ended December 31, 2019, Ultra derived its revenues from the sale of its natural gas and associated condensate produced from wells operated by the Company in the Green River Basin in southwest Wyoming and ownership interests in wells operated by another operator in the same area.

During 2019, 96% of the Company’s production and 86% of its revenues were attributable to natural gas, with the balance attributable to associated condensate and crude oil.

The Company’s natural gas and oil revenues are determined by prevailing market prices in the Rocky Mountain region of the United States, specifically, southwest Wyoming, as virtually all of its natural gas is sold at the Inside FERC First of Month Index for Northwest Pipeline — Rocky Mountains (“NwRox”). The NwRox and New York Mercantile Exchange (“NYMEX”) is the price that is reflective of the Company’s gas sold in the Opal, Wyoming area.

The NwRox price can be volatile, particularly in peak winter and summer periods, as evidenced in December 2019 when natural gas at that delivery point was selling for $0.97 per MMBtu above NYMEX pricing for natural gas.  During 2019, the negative differential of NwRox to Henry Hub averaged $0.04 per MMBtu, with a range of negative $0.74 per MMBtu to a positive differential of $0.97 per MMBtu for first of month Inside FERC basis at Opal.

Natural Gas Marketing

Ultra currently sells all its natural gas production to a diverse group of third-party, non-affiliated entities in a portfolio of transactions of various durations and prices (daily, monthly and longer term). The Company’s customer base includes a significant number of customers situated in the various regions of the United States. The sale of the Company’s natural gas is “as produced”.

Midstream services.    For its natural gas production in Wyoming, the Company has entered into various gathering and processing agreements with midstream service providers that gather, compress and process natural gas owned or controlled by the Company from its producing wells in the Pinedale Anticline and Jonah fields. Under these agreements, the midstream service providers continue to maintain and upgrade the facilities in southwest Wyoming to ensure reliability and certainty of operations. The Company believes that the capacity of the midstream infrastructure related to its production will continue to be adequate to allow it to sell all its available natural gas production.

Basis differentials.    The market price for natural gas is influenced by a number of regional and national factors which are beyond the Company’s ability to control. These factors include, among others, weather in the western United States, natural gas supplies, imports from Canada, natural gas demand, inventory levels in natural gas storage fields, and natural gas pipeline capacity to export gas from the basins where the Company’s production is located. See Item 1A. “Risk Factors” for more information about risks to our financial condition and business results associated with basis differentials.

The Rocky Mountain region is a net exporter of natural gas because local natural gas production exceeds local demand, especially during non-winter months. As a result, natural gas production in southwest Wyoming has from time to time sold at a discount relative to other U.S. natural gas production sources or market areas. These regional pricing differentials, or discounts, are typically referred to as “basis” or “basis differentials” and are reflective, to some extent, of (i) the costs associated with transporting the Company’s gas to markets in other regions or states, and (ii) the availability of pipeline capacity to move the Company’s gas to market.

Following the completion of the Rockies Express and Ruby pipelines, the average annual basis for NwRox averaged 5.6% below Henry Hub from 2012 through 2016. The additional capacity of these two pipelines has had a significant positive impact on the value that the Company receives for its natural gas production in southwest Wyoming, as compared to prior years when constraints were prevalent in the region. However, from 2017 to 2018, NwRox basis weakened from levels realized in 2012 through 2016 mainly due to weakening fundamentals in the Company’s core delivery area, California, and increasing flows from regions that produce significant quantities of oil and are connected by gas pipelines to the California market. In 2019, NwRox basis improved to average 98.6% of Henry Hub due increased demand and reduced supply in Western US markets. What has become more pronounced over the last several years is a widening and favorable distinction between natural gas priced based on NwRox compared to Colorado Interstate Gas (“CIG”).  Over the course of 2019, NwRox outperformed CIG by approximately $0.45 per MMBtu with CIG pricing at 81.6% of Henry Hub.

While trades indicate that the basis differentials for the forward-looking basis market for 2020 and 2021 are negative to Henry Hub by approximately $0.23 per MMBtu and $0.36 per MMBtu, respectively, the winter seasons of 2018/2019 and 2019/2020 demonstrate the potential for NwRox basis to trade at a significant premium to Henry Hub during the winter seasons. The actual results for January and February 2020 were positive by $1.00 per MMBtu and $0.07 per MMBtu, respectively.

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The table below provides a historical perspective on average quarterly basis differentials for Wyoming natural gas (NwRox). The basis differential is expressed as a percentage of the Henry Hub price as reported by Inside FERC Report from S&P and Platt’s M2M (Mark to Market) Report on December 31, 2019 and 2018, respectively.

 

 

 

2019

 

 

 

1st Quarter

 

 

2nd Quarter

 

 

3rd Quarter

 

 

4th Quarter

 

NwRox

 

 

120

%

 

 

79

%

 

 

86

%

 

 

104

%

NYMEX (per MMBtu)

 

$

3.15

 

 

$

2.64

 

 

$

2.23

 

 

$

2.50

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018

 

 

 

1st Quarter

 

 

2nd Quarter

 

 

3rd Quarter

 

 

4th Quarter

 

NwRox

 

 

83

%

 

 

70

%

 

 

80

%

 

 

103

%

NYMEX (per MMBtu)

 

$

3.00

 

 

$

2.80

 

 

$

2.90

 

 

$

3.64

 

 

Oil Marketing

Wyoming.    The Company markets its Wyoming condensate to various purchasers, which are primarily refiners in the Salt Lake City, Utah area. The Company’s condensate realized pricing is typically based on New York Mercantile Exchange crude futures daily settlement prices, adjusted for a negotiated location/transportation differential. All of the Company’s condensate sales are denominated in U.S. dollars per barrel and are paid monthly. The Company routinely maintains only operating inventories of condensate production and sells its product on an “as produced” basis. A portion of the Company’s condensate sales are entered into by its operating partners in the Pinedale field. Over 93% of oil is transported via pipeline, thereby greatly reducing the cost of transportation. During 2019, the Company realized a positive differential of $2.83 per Bbl, to a West Texas Intermediate price. The improvement in the differential was a result of strong refining demand for the quality of condensate produced in the Pinedale area. This trend of strengthening oil differentials is expected to continue in 2020, as evidence by the contracts in place through 2020 at a positive differential of $3.74 per Bbl. With the drastic drop in demand for Refined Products due to the response to COVID-19, Salt Lake area refineries may reduce their demand for Crude Oil.  There is a risk that regional storage for Crude Oil may be insufficient for area producers including Ultra to continue full production rates in the second quarter of 2020. Please see “Risk Factors-- Outbreaks of communicable diseases could adversely affect our business, financial condition and results of operations” and “--The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

Derivatives

The Company, from time to time and in the regular course of its business, enters into hedges for volumes equivalent to a portion of expected future production volumes, primarily through the use of financial swaps, collars and puts with creditworthy financial counterparties (See Note 8 for additional information), or through the use of fixed price, forward sales of physical product. Under the Company’s Credit Agreement, the Company is subject to minimum hedging requirements through March 31, 2020, after which there is no minimum hedging requirement from the lenders. During the quarterly period beginning on September 30, 2019 and ending on March 31, 2020, the Company was required to hedge a minimum of 50% of projected proved developed producing natural gas reserve volumes projected to be produced in the specified quarter.

The Company considers the requirements of the Credit Agreement when developing its hedging policy.  The Company’s management and board of directors has a Hedge Committee that reviews the forecast production, the requirements under the Credit Agreement, and the market outlook to determine the timing and the manner in which to hedge with the underlying goal to provide a predictable level of cash flow while preserving some flexibility to participate in upward price movements.

Major customers

A major customer is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2019, sales to Nevada Power Company and Pacific Gas and Electric accounted for 11.1% and 10.2% of our total revenue, respectively. In 2018 and 2017, the Company had no single customer that represented 10% or more of the Company’s total revenues.

The Company maintains credit policies intended to mitigate the risk of uncollectible accounts receivable related to the sale of natural gas and condensate as well as commodity derivatives. A more complete description of the Company’s credit policies is described in Note 15. The Company takes measures to ensure collectability with its purchasers through regular credit monitoring and reviews.  As necessary, the Company requires prepayment, letters of credit or parental guarantees from its purchasers for the periods of exposure.  The Company did not have any outstanding, uncollectible accounts for its natural gas and oil sales at December 31, 2019.

Regulatory Matters

The Company’s oil and gas operations are subject to a number of regulations. Governing agencies may include one or more of the following levels: federal, regional, state, county, municipality, Tribal or other public entities. In general, the purposes of these regulations are to

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prevent waste of oil and natural gas resources, protect the rights of surface and mineral owners, regulate interstate transportation of oil and gas, and to govern environmental quality. Common forms of regulations may include:

 

Notification to stakeholders of proposed and ongoing operations;

 

Nondiscrimination statutes;

 

Royalty and related valuation requirements;

 

On-site security and bonding requirements;

 

Location and density of drilling;

 

Method of drilling, completing and operating wells;

 

Measurement and reporting of oil and gas;

 

Rates, terms and conditions applicable to the interstate transportation of oil and gas;

 

Production, severance and ad valorem taxes;

 

Management of produced water and waste; and

 

Surface use, reclamation and plugging and abandonment of wells.

A significant portion of the Company’s operations are located on federal lands in the Pinedale and Jonah Fields of Sublette County, Wyoming. The development activities in these fields are subject to the regulation of the U.S. Bureau of Land Management (“BLM”) which is responsible for governing their surface and mineral rights and regulating certain development activities in these fields. As required under the National Environmental Policy Act, an Environmental Impact Statement (“EIS”) was prepared to quantify and address potential impacts of natural gas development in both the Pinedale and Jonah fields. In March 2006, the BLM issued its Record of Decision (“ROD”) which provides broad authorization for the development activities currently occurring in the Jonah Area. In September 2008, the BLM issued its ROD that currently governs the development activities in the Pinedale Area. In addition to the overarching authorizations provided by the Jonah and Pinedale RODs, BLM issues site-specific authorizations such as rights of way and permits to drill on an ongoing basis.

The Pinedale ROD includes some significant components to ensure the orderly and responsible development of natural gas concurrent to minimizing the environmental impact. Some of these components include:

 

Year-round operations on multi-wells pads;

 

Liquid gathering systems to reduce truck traffic and minimize impacts to air quality and wildlife;

 

Monitoring of key wildlife species and mitigation of monitored impacts;

 

Advanced emission reductions including best practices such as controlled drill rigs;

 

Spatial progression of development to address specific surface and wildlife issues;

 

Annual meeting and long-range planning requirements to allow for socioeconomic predictability;

 

Adaptive Management to consider current and changing conditions and facilitate common-sense solutions; and

 

Suspension of flank acreage until core acreage is developed and returned to a functioning habitat.

While the majority of the Company’s operations in Wyoming are covered by the Pinedale ROD, provisions of the Jonah ROD similarly ensure responsible and orderly development of the Jonah field while minimizing the environmental impact:

 

Annual reporting and long-range planning requirements to allow for planned mitigation and socioeconomic predictability;

 

Emission reduction report to ensure air quality goals are met;

 

Annual water well monitoring reports; and

 

Flareless-completion technology to reduce noise, visual impacts and air emissions.

The State of Wyoming maintains governance over some of the more traditional state-regulated matters such as individual well drilling permits, spacing and pooling, wellbore construction, as well as its own regulations on safety and environmental matters. The WOGCC has authorized drilling density up to one well per five acres in the Pinedale field and up to one well per ten acres in the Jonah field.

Regulations are well documented and the Company believes that it is substantially in compliance with current applicable laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. However, changes to certain existing regulations are beyond the control of the Company and could introduce uncertainty and additional costs. See Item1A. “Risk Factors” for additional information regarding environmental regulations.

In December 2018 and January 2019, a portion of the federal government shut down after Congress failed to pass a continuing resolution.  This shut-down included all nonessential personnel at the BLM, including BLM staff tasked with processing drilling permits and sundries.  The Company has adequate inventory of approved applications for permit to drill if and when the Company’s elects to resume its drilling program,

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but any changes or deviations from what is approved in these permits cannot be approved during a shut-down, should another one occur, thus creating an execution risk.  In addition, such government disruptions could delay or halt the granting and renewal of the permits, approvals, and certificates required to conduct our operations.  

Mineral Leasing Act

The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease can be canceled in a proceeding instituted by the United States Attorney General. The Company’s subsidiaries that own mineral leases qualify as a corporation formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that holders of the Company’s equity interests may be citizens of foreign countries that are determined to be non-reciprocal countries under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination.

Environmental and Occupational Safety and Health Matters

Surface Damage Acts

Several states, including Wyoming, and some tribal nations have enacted surface damage statutes. These laws are designed to compensate for damages caused by oil and gas development operations. Most surface damage statutes contain entry and negotiation requirements to facilitate contact between the operator and surface owners. Most also contain binding requirements for payments by the operator in connection with development operations. Costs and delays associated with surface damage statutes could impair operational effectiveness and increase development costs.

Environmental Regulations

General.    The Company’s exploration, drilling and production activities from wells and oil and natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products are subject to numerous stringent federal, state and local laws and regulations relating to environmental quality, including those relating to oil spills and pollution control. These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. The oil and gas exploration and production industry has been and continues to be the subject of increasing scrutiny and regulation by environmental authorities.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. However, it is anticipated that, absent the occurrence of an extraordinary event, compliance with these laws and regulations will not have a material effect upon the Company’s operations, capital expenditures, earnings or competitive position.

Solid and Hazardous Waste.    The Company has previously owned or leased and currently owns or leases, numerous properties that have been used for the exploration and production of oil and natural gas for many years. Although the Company utilized standard operating and disposal practices, hydrocarbons or other solid wastes may have been disposed of or released on or under such properties or on or under locations where such wastes have been taken for disposal. In addition, many of these properties are or have been operated by third parties over whom the Company has no control, nor has ever had control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and natural gas wastes and properties have gradually become stricter over time. Under current and evolving law, it is possible the Company could be required to remediate property, including ground water, impacted by operations of the Company or by such third-party operators, or impacted by previously disposed wastes including performing remedial plugging operations to prevent future, or mitigate existing contamination.

Although oil and gas wastes generally are exempt from regulation as hazardous wastes under the federal Resource Conservation and Recovery Act (“RCRA”) and some comparable state statutes, it is possible some wastes the Company generates presently are or in the future may be subject to regulation under RCRA and state analogs, even as non-hazardous wastes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and there is no guarantee that the EPA or the states will not adopt more stringent requirements in the future. For example, in December 2016, the EPA and several environmental groups entered into a consent decree under which the EPA committed to propose new regulations for the management of oil and gas wastes under RCRA Subtitle D (which relates to non-hazardous wastes) or sign a determination that a revision of existing rules is unnecessary. In April 2019, the EPA made the determination that revisions to the regulations were not necessary at that time, concluding that

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any adverse effects related to oil and gas waste were more appropriately and readily addressed within the framework of existing state regulatory programs. Furthermore, certain wastes generated by the Company’s oil and natural gas operations that are currently exempt from designation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.

In addition, current and future regulations governing the handling and disposal of Naturally Occurring Radioactive Materials (“NORM”) may affect our operations. For example, in Wyoming any waste material exceeding specified thresholds is subject to controls and guidance by the Wyoming Department of Environmental Quality Solid and Hazardous Waste Division, which determines how and where NORM wastes will be disposed of.

Hydraulic Fracturing.    Many of the Company’s exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. Hydraulic fracturing activities are typically regulated by state oil and gas commissions. The EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the federal Safe Drinking Water Act (“SDWA”) involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Congress has periodically considered legislation to amend the SDWA to remove the exemption from permitting and regulation provided to injection for hydraulic fracturing (except where diesel is a component of the fracturing fluid) and to require the disclosure and reporting of the chemicals used in hydraulic fracturing. This type of federal legislation, if adopted, could lead to additional regulation and permitting requirements that could result in operational delays making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and operating costs.

In addition, the EPA has issued guidance regarding federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. Further, in December 2016 the EPA released its final report on a wide-ranging study on the effects of hydraulic fracturing resources. While no widespread impacts from hydraulic fracturing were found, the EPA identified a number of activities and factors that may have increased risk for future impacts.  Furthermore, a number of public and private studies are underway regarding the connection, if any, between the disposal of waste water associated with hydraulic fracturing and observed seismicity in the vicinity of such disposal operations. These studies and the EPA’s enforcement initiative for the energy extraction sector could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Some states, including Wyoming, have adopted, and other states are considering adopting, regulations that require disclosure of the chemicals in the fluids used in hydraulic fracturing or well stimulation operations. Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding permitting, casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Although none of the Company’s properties are in jurisdictions where the moratoria have been imposed, it is possible the jurisdictions where the Company’s properties are located may adopt such limits or other limits on hydraulic fracturing in the future. In December 2017, BLM rescinded regulations that it previously enacted for hydraulic fracturing activities on federal lands; that rescission has been challenged by several environmental groups and states in ongoing litigation. Further, the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and is working on regulations for wastewater generated by hydraulic fracturing.

Finally, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes.  In Oklahoma, for example, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity.  Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells.  Although our operations are not located in those jurisdictions, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations.

Superfund.    Under the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, liability, generally, is joint and several for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties (“PRPs”), include current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance, persons who disposed of or arranged for the disposal of the hazardous substances found at such a facility, and in some cases the parties transporting such hazardous substances to the facility at issue. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to releases and threats of releases to protect the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of its operations, adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past, and the Company has generated and will generate wastes that fall within CERCLA’s definition of hazardous substances. The Company may also be an owner or operator of facilities on which hazardous substances have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages, as a past or present owner or operator or as an arranger. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties may have been operated by third parties whose treatment and disposal or release of wastes was not under our control. Many states have comparable laws imposing liability on similar classes of persons for releases, including for releases of materials that may not be included in CERCLA’s definition of hazardous substances.

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To its knowledge, the Company has not been named a PRP under CERCLA (or any comparable state law) nor have any prior owners or operators of its properties been named as PRPs related to their ownership or operation of such property.

National Environmental Policy Act.    NEPA provides that, for federal actions significantly affecting the quality of the human environment, the federal agency taking such action must prepare an Environmental Assessment (“EA”) or an EIS. In the EIS, the agency is required to evaluate alternatives to the proposed action and the environmental impacts of the proposed action and of such alternatives. Actions of the Company, such as drilling on federal lands, to the extent the drilling requires federal approval, may trigger the requirements of the NEPA, including the requirement that an EA or EIS be prepared. The requirements of the NEPA may result in increased costs, significant delays and the imposition of restrictions or obligations on the Company’s activities, including but not limited to the restricting or prohibiting of drilling. Moreover, in January 2020, the White House Council on Environmental Quality (“CEQ”) proposed changes to NEPA regulations designed to overhaul the system and speed up federal agencies’ approval of projects. Among other things, the rule proposes to narrow the definition of “effects” to exclude the terms “direct,” “indirect,” and “cumulative” and redefine the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.” Changes to the NEPA regulations could impact our operations and our ability to obtain governmental permits. We continuously evaluate the effect of new rules on our business

Oil Pollution Act.    The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act (“CWA”), imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and for a variety of public and private damages. Although defenses and limitations exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, the Company could be liable for costs and damages.

Clean Air Act.    The Clean Air Act (“CAA”) and analogous state laws regulate air emissions from stationary and mobile sources and establishes National Ambient Air Quality Standards for six criteria pollutants. The CAA is a federal law, but states, tribes and local governments do much of the work to develop EPA-approved plans to achieve these standards and meet the CAA’s requirements. Federal and state laws generally require new and modified sources of air pollutants to obtain permits prior to commencing construction, which may require, among other things, stringent emission controls. Administrative agencies can bring actions for failure to comply with air pollution regulations or permits and generally enforce compliance through administrative, civil or criminal enforcement actions, which may result in fines, injunctive relief and imprisonment.

The New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs under the CAA impose specific requirements affecting the oil and gas industry for compressors, controllers, dehydrators, storage tanks, natural gas processing plants, completions and certain other equipment. Periodic review and revision of these rules by federal and state agencies may require changes to our operations, including possible installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.

In June 2016, the EPA finalized rules to reduce methane and volatile organic compound (“VOC”) emissions from new, modified or reconstructed sources in the oil and natural gas sector; however, in September 2018, under a new administration, the EPA proposed to remove transmission and storage activities from the purview of the rules, thereby rescinding the VOC and methane emissions limits applicable to those activities. The proposed rule would also rescind the methane limit emissions for production and processing sources but would maintain emissions limits for VOCs. In the alternative, the EPA also proposed to simply rescind the methane requirements for all oil and natural gas sources, without removing any activities from the source category. Similarly, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it had previously enacted to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands; California and New Mexico have challenged that rule in ongoing litigation.  In addition, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending (as of October 2019, the EPA had requested a stay of the litigation pending the outcome of its proposed overhaul of the 2016 methane requirements). Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements and cause major delays in construction, effectively depressing new development. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which could be significant.

Clean Water Act.    The CWA and analogous state laws restrict the discharge of pollutants, including produced waters and other oil and natural gas wastes, into state waters and waters of the United States, a term broadly defined to include, among other things, certain wetlands. Under the CWA, permits must be obtained for the discharge of pollutants into waters of the United States. The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants, oil, and hazardous substances and also imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities.

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The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit. In June 2015, the EPA and the Army Corps of Engineers (“Corps”) issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction over wetlands (the “Clean Water Rule”). The Clean Water Rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals, but on January 22, 2018, the U.S. Supreme Court ruled that jurisdiction to hear challenges to the rule lies with the federal district courts, and the Sixth Circuit’s stay was dissolved in February 2018. On July 27, 2017, the EPA published a proposed rule to rescind the Clean Water Rule and re-codify the regulatory text that existed prior to 2015 defining the “waters of the United States.In December 2018, the EPA and the Corps issued a proposed rule revising the WOTUS definition that would provide discrete categories of jurisdictional waters and tests for determining whether a particular water body meets any of those classifications. In October 2019, the EPA issued a final rule repealing the Clean Water Rule (which became effective in December 2019 and already has been challenged in federal district courts in New Mexico, New York, and South Carolina). In January 2020, the EPA announced a final rule redefining “waters of the United States.” Several groups have already announced their intentions to challenge the final revision rule. To the extent the repeal and revision rules are successfully challenged, and the Clean Water Rule is enforced in jurisdictions in which we operate or a replacement rule expands the scope of the CWA jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.  

Also, in 2016, the EPA finalized new wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.

Endangered Species Act.    The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”), and special protections are provided to bald and golden eagles under the Bald and Golden Eagle Protection Act. The Company conducts operations on federal and other oil and natural gas leases that have species, such as raptors, that are listed and species, such as sage grouse, that could be listed as threatened or endangered under the ESA.  On February 11, 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make listing decisions and critical habitat designations where necessary for over 250 species.  The U.S. Fish and Wildlife Service issued a 7-Year National Listing Workplan in September 2016. However, on July 25, 2018, the U.S. Fish and Wildlife Service proposed three revisions to regulations regarding critical habitat designation, interagency cooperation, and protection of threatened species that it believes are necessary to address industry and landowner concerns. The U.S. Department of the Interior also issued an opinion on December 22, 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In response to this opinion, two separate lawsuits were filed on May 24, 2018 in the U.S. District Court for the Southern District of New York challenging the Department of the Interior’s interpretation of the MBTA. On September 5, 2018, eight states also filed suit in the U.S. District Court for the Southern District of New York challenging the opinion. All such litigation is ongoing. The identification or designation of previously unprotected species as threatened or endangered in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Climate Change Legislation.    More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”), including methane and carbon dioxide, may be adopted and could cause the Company to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions.  Although the Supreme Court struck down the permitting requirements as applicable to GHG emissions, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA has established GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. The Company has submitted all required annual reports to date. Although the rule does not limit the amount of GHGs that can be emitted, it could require us to incur significant costs to monitor, keep records of, and report GHG emissions associated with our operations.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international level, the United States was one of 175 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020. However, on June 1, 2017, President Trump announced that the United States will withdraw from the Paris Agreement, and on November 4, 2019, the U.S. submitted formal notification of its withdrawal to the United Nations.  The withdrawal will take effect one year from delivery of the notification, although there is a possibility that a new administration could choose to rejoin the Paris Agreement. Various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

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Any legislation or regulatory programs to reduce GHG emissions could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for 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.  Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by our customers or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Worker Safety.    The Occupational Safety and Health Act (“OSHA”) and analogous state laws regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. For example, under a new OSHA standard limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021. Failure to comply with OSHA requirements can lead to the imposition of penalties. For example, in December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.

The Company believes that it is in substantial compliance with current applicable environmental and occupational health and safety laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company.

Employees

As of December 31, 2019, the Company had 151 full-time employees, including officers. The Company believes that its relationship with its employees is satisfactory. None of our employees are represented by a labor union or subject to a collective bargaining agreement.

Seasonality and Cyclicality

Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in the areas in which the Company operates.  These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations.  For example, the Company’s operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.

The demand for natural gas typically decreases during the summer months and increases during the winter months.  Seasonal anomalies sometimes lessen or amplify this fluctuation.  In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.  As a corollary, the demand for our products can be impacted by weather in the western United States from temperature fluctuations outside of normal ranges, moisture levels in the Pacific Northwest to the extent it impacts hydroelectric power generation, and more broadly across the United States when there are unusual cold events or lack of winter weather.

Competition

The oil and gas industry is intensely competitive, and we compete with other companies in our industry that have more extensive resources than we do or that may have other competitive advantages or disadvantages.  We compete with other companies in the acquisition of properties, in the search for and development of reserves, in the production and sale of natural gas and crude oil, and for the labor and equipment required to conduct our operations.  Our competitors include major oil and natural gas companies, other independent oil and natural gas companies, and individual producers and operators.

Principal Executive Offices

The Company is incorporated under the laws of Yukon, Canada, with headquarters in Englewood, Colorado.  The principal executive offices are located at 116 Inverness Drive East, Suite 400, Englewood, Colorado, 80112.  The main telephone number is (303) 708-9740.

Item 1A.

Risk Factors.

An investment in our common stock involves certain risks.  If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations, and cash flows.  In any such circumstance and others described below, the trading price of our securities could decline and investors could lose part or all of their investment.

We have concluded that we need to restructure our balance sheet to continue as a going concern over the long term, and we can provide no assurances of the terms of any such restructuring transaction in which we may engage or how any such transaction will impact

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our security holders. We may need to seek relief under Chapter 11 of the United States Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act, which could result in little or no consideration to our debt and equity holders.

As a result of our significant indebtedness and extremely challenging current market conditions, we believe we will require a significant restructuring of our balance sheet in order to continue as a going concern in the long term.  We have based this belief on assumptions and estimates which are to some degree subjective and may vary considerably from actual results, and we could spend our available financial resources less or more rapidly than currently expected.  

In February and March 2020, we entered into confidentiality agreements and commenced discussions with certain holders of the Company’s long-term debt and their legal and financial advisors.  Negotiations and discussions with certain debtholders and their advisors are ongoing, although as of the date of this filing no definitive agreements have been reached regarding any amendments, restructurings or other transactions relating to the Company’s indebtedness.

There can be no assurance that our efforts will result in any agreement or what the terms of any agreement will be.  If an agreement is reached and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act in order to implement an agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings.  We also may conclude that it is necessary to initiate proceedings under Chapter 11 of the United State Bankruptcy Code to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring.  In either case, such a proceeding could be commenced in the near term.  If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration.  If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment.  It is also possible that our other stakeholders, including holders of our Second Lien and Unsecured Notes, will receive little or no consideration for their claims.

The audit report we received with respect to our fiscal year 2019 consolidated financial statements contains an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern. Our Credit Agreement and Term Loan Agreement require us to deliver audited, consolidated financial statements without a going concern or like qualification or exception. As a result, unless we obtain a waiver of this requirement, subject to a 30-day grace period, we will be in default under our Credit Agreement and Term Loan Agreement after we deliver our financial statements to the lenders thereunder. Our failure to obtain a waiver of this requirement under the Credit Agreement and Term Loan Agreement within the applicable grace period could result in an acceleration of all of our outstanding debt obligations thereunder.

The sustained periods of low natural gas prices combined with the recent precipitous drop in crude oil prices and our substantial indebtedness led us to determine that there is substantial doubt about our ability to continue as a going concern.  Additionally, there is substantial doubt regarding our ability to maintain adequate liquidity through our borrowing base and commitments thereunder for the twelve month period following the issuance date of our audited, consolidated financial statements for the fiscal year ended December 31, 2019.  As a result, our independent registered public accounting firm included an explanatory paragraph with respect to this uncertainty in its report that is included with our financial statements in this Annual Report on Form 10-K.  

Under our Credit Agreement and Term Loan Agreement, we are required to deliver audited, consolidated financial statements without a going concern or like qualification or explanation. Because the audit report prepared by our auditors with respect to the financial statements in this Annual Report on Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern, we will be in default under each of the Credit Agreement and Term Loan Agreement on April 14, 2020 when we deliver our financial statements to the lenders under the Credit Agreement and the Term Loan Agreement, respectively. We expect that we will be precluded from drawing additional amounts under the Credit Agreement while the default exists. There is a 30-day grace period related to this covenant in each of the Credit Agreement and the Term Loan Agreement. If we do not obtain a waiver or other suitable relief from the lenders under the Credit Agreement or the Term Loan Agreement before the expiration of the 30-day grace period, an event of default under the Credit Agreement and Term Loan Agreement would occur. At this time, we do not expect to obtain a waiver of this requirement.

If an event of default occurs under our Credit Agreement and Term Loan Agreement, the lenders could accelerate the loans outstanding under the Credit Agreement and Term Loan Agreement. In addition, if the lenders under our Credit Agreement and Term Loan Agreement accelerate the loans outstanding thereunder, we will then also be in default under the indentures related to our Second Lien Notes and our Unsecured Notes. If we default under those indentures, the holders of the Second Lien Notes and Unsecured Notes could accelerate those notes.

If our lenders or our noteholders accelerate the payment of amounts outstanding under the Credit Agreement, Term Loan Agreement, Second Lien Notes, or the Unsecured Notes, respectively, we do not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. It is unlikely that we could obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof.  If we fail to obtain sufficient additional capital to repay the outstanding indebtedness and provide sufficient liquidity to meet our operating needs, it may be necessary for us to seek protection from creditors under Chapter 11 of the United States Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act, or an involuntary petition for bankruptcy may be filed against us in the U.S. or in Canada.  Accordingly, there is substantial doubt regarding our

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ability to continue as a going concern within one year from the issuance date of our audited, consolidated financial statements for the fiscal year ended December 31, 2019.

We have significant indebtedness. Our level of indebtedness could adversely affect our business, results of operations, and financial condition. If we are unable to comply with the financial and non-financial covenants governing our indebtedness or obtain waivers of any defaults that occur with respect to our indebtedness, or amend, replace or refinance any or all of the agreements governing our indebtedness and/or otherwise secure additional capital, we may be unable to meet our expenses and debt obligations.

As of April 10, 2020, we had the following principal amounts outstanding under our Revolving Credit Facility, our Term Loan Facility (as defined in Note 6), our Second Lien Notes, 2022 Notes and our 2025 Notes:

 

$43.0 million under the Revolving Credit Facility;

 

$966.3 million under the Term Loan Facility;

 

$586.8 million with respect to the Second Lien Notes;

 

$150.4 million with respect to the 2022 Notes; and

 

$225.0 million with respect to the 2025 Notes.

Our indebtedness affects our operations in several ways, including:

 

requiring us to dedicate a substantial portion of our cash flow to service our existing debt, thereby reducing the cash available to finance our operations and other business activities, and limiting our flexibility to plan for or react to changes in our business and the industry in which we operate;

 

increasing our vulnerability to economic downturns and adverse developments in our business;

 

limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

 

placing restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

 

placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;

 

limiting our ability to deduct our net interest expense; and

 

making it more difficult for us to satisfy our obligations under our existing indebtedness and increasing the risk that we may default on our debt obligations.

Our ability to meet our expenses and debt service 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 economic conditions and governmental regulation. We depend on our Revolving Credit Facility for future capital and liquidity needs, because we use operating cash flows for investing activities. To the extent future commitments under the Revolving Credit Agreement decrease below the outstanding balance of the Revolving Credit Facility, because of a downward redetermination of the borrowing base and commitments, the Company would be required to enter into a mandatory repayment schedule to satisfy the deficiency.  Should the lenders not support such a repayment schedule, intramonth liquidity for the Company could be inadequate to meet obligations on a timely basis.  In the event that the borrowing base is reduced to an amount that is less than the outstanding borrowings under the Term Loan Facility, then commitments under the Revolving Credit Facility would be reduced to zero and Ultra Resources would become subject to additional coverage tests under the Term Loan Facility. Among these new requirements is an asset coverage test and, if not satisfied, Ultra Resources would be required to make mandatory prepayments to the lenders under the Term Loan Facility in order to cure any deficiency.  Failure to make such required payments would result in an event of default under the Term Loan Facility.

There are covenants in certain agreements governing our indebtedness. In many instances, a default under one of the agreements governing our indebtedness can, if not cured or waived, result in a default under certain of our other indebtedness agreements. A default on our obligations and/or an acceleration of our indebtedness by our lenders or noteholders, as applicable, would have a material adverse impact on our business, financial condition, results of operations, cash flows, and the trading price of our securities.

The Fifth Amendment to the Revolving Credit Facility removed certain financial covenants such that the Company is no longer subject to an interest coverage ratio, a current ratio, a net leverage ratio or an asset coverage ratio. However, the Fifth Amendment to the Revolving Credit Facility introduced a new maximum capital expenditure covenant, which limits the amount of capital expenditures the Company can make per fiscal quarter, subject to certain carry-forward rights for unused amounts.

Additionally, the Sixth Amendment to the Revolving Credit Facility dated February 14, 2020 (i) reduced the excess cash threshold, a part of the anti-cash hoarding provisions, from $25 million to $15 million at all times borrowings are outstanding under the Revolving Credit Agreement and (ii) established quarterly borrowing base redeterminations, with the next redetermination occurring on July 1, 2020, and on each October 1, January 1, April 1 and July 1 thereafter.

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As previously described, the audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern. Such inclusion is a default under the Credit Agreement and Term Loan Agreement. If our lenders accelerate the payment of amounts outstanding under our Revolving Credit Facility or Term Loan Facility following the expiration of the 30-day grace period, we do not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. In addition, the acceleration of the payments outstanding under our Revolving Credit Facility or the Term Loan Facility could result in a cross-default under the indentures governing the Second Lien and Unsecured Notes. We could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, we cannot provide any assurances that we will be successful in obtaining capital from such transactions on acceptable terms, or at all, and if we were unable to obtain sufficient additional capital to repay the outstanding indebtedness and sufficient liquidity to meet our operating needs, it may be necessary for us to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act, or an involuntary petition for bankruptcy may be filed against us in the U.S. or in Canada.

The borrowing base under our Revolving Credit Facility may be reduced, which could limit us in the future and negatively impact our ability to meet our financial obligations.

Based on the Sixth Amendment, the commitment amount under the Revolving Credit Facility was reduced from $120 million to $100 million with the associated borrowing base being set at $1.075 billion, effective April 1, 2020. Under the Sixth Amendment, the borrowing base is redetermined quarterly and the next borrowing base redetermination date is scheduled to be on July 1, 2020.  In addition, either we or the lenders may request an interim redetermination twice per year or in conjunction with certain acquisitions or sales of oil and gas properties.  Our borrowing base may decrease as a result of lower commodity prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness, or for any other reason.  

An inadequate borrowing base and/or commitment amount could potentially have an adverse impact on our liquidity and the ability to meet our financial obligations.  In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under the Revolving Credit Facility may be limited and we could be required to pay indebtedness in excess of the redetermined borrowing base. If we are required to repay the indebtedness under our Revolving Credit Facility as a result of a downward borrowing base redetermination, we may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, at commercially reasonable rates to meet our obligations, including any such debt repayment obligations.

Our common shares were recently delisted from The NASDAQ Global Select Market and trade in an over-the-counter market. This may negatively affect our stock price and liquidity.

As previously disclosed, on August 8, 2019, our common shares were delisted from The NASDAQ Global Select Market. Trading in our common shares is now conducted in the over-the-counter markets on the OTC Bulletin Board and the liquidity of our common shares may likely be reduced or impaired, not only in the number of shares which could be purchased and sold, but also through delays in the timing of the transactions. There may also be a reduction in our coverage by security analysists and the news media, thereby resulting in potential lower prices for our common shares than might otherwise prevail. The delisting of our common shares may also result in other adverse consequences, including lower demand for our shares, adverse publicity and a reduced interest in our Company from investors, analysts and other market participants.

Investments in securities trading on the over-the-counter markets are generally less liquid than investments in securities trading on a national securities exchange. In addition, the trading of our common shares on the over-the-counter markets could have other negative implications, including the potential loss of confidence in us by suppliers, customers and employees and the loss of institutional investor interest in our common shares. This could further depress the trading price of our common shares and could also have a long-term adverse effect on our ability to raise capital.

There can be no assurance that our common shares will continue to trade on the over-the-counter markets or that any public market for the common shares will exist in the future, whether broker-dealers will continue to provide public quotes of the common shares on this market, whether the trading volume of the common shares will be sufficient to provide for an efficient trading market, whether quotes for the common shares may be blocked in the future, or that we will be able to relist the common shares on a national securities exchange. If we fail to remain current in our reporting requirements, the market liquidity of our securities could be harmed by impacting the ability of broker-dealers to trade our securities and the ability of stockholders to sell their securities in the secondary market.

If we cannot obtain sufficient capital when needed, we will not be able to continue with our business strategy.

Our business strategy has historically included maintaining a portfolio of properties that provide long-term, profitable growth through development in areas that support sustainable, lower-risk, repeatable, high-return drilling projects. In the future, we may not be able to obtain financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. Further. fluctuations in oil, NGL and natural gas prices can create fiscal challenges for the oil and gas industry. These conditions have impacted companies in the oil and gas industry and the Company’s spending and operating plans and may continue to do so in the future. There may be unexpected business impacts from market uncertainty, including volatile changes in currency exchange rates, inflation, interest rates, defaults of suppliers and general levels of investing and consuming activity, as well as a potential impact on the Company’s credit ratings, which could

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affect its liquidity and general ability to obtain financing. If we cannot raise the capital required to implement our historical business strategy, we may be required to curtail operations, which could adversely affect our financial condition and results of operations.

Our substantial indebtedness, liquidity concerns, the credit ratings assigned to our debt by independent credit rating agencies and historical emergence from bankruptcy in 2017 could adversely affect our business and relationships.

Our substantial indebtedness, liquidity concerns, the credit ratings assigned to our debt by independent credit rating agencies and our historical emergence from Chapter 11 bankruptcy proceedings in 2017 could adversely affect our business and relationships with customers, employees, and suppliers. Due to uncertainties, many risks exist, including the following:

 

key suppliers could terminate their relationship or require financial assurances or enhanced performance;

 

the ability to renew existing contracts and compete for new business may be adversely affected;

 

the ability to attract, motivate, and/or retain key executives and employees may be adversely affected;

 

employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and

 

competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial conditions, and reputation. We cannot assure you that having been subject to bankruptcy protections will not adversely affect our operations in the future.

Transfers or issuances of our equity may impair our ability to utilize our U.S. federal net operating losses.

Under U.S. federal income tax law, a corporation is generally permitted to deduct from its taxable income net operating losses (“NOLs”) carried forward from prior years. We have NOL carryforwards of approximately $2.3 billion as of December 31, 2019. Our ability to utilize our U.S. federal NOL carryforwards to offset future taxable income and to reduce income tax liability may be substantially limited if we experience an “ownership change” (as defined in section 382 of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more shareholders owning 5% or more of a corporation’s common stock have aggregate increases in ownership of such stock of more than 50 percentage points over the prior three-year period. An “ownership change” occurred when our chapter 11 plan of reorganization became effective. Transfers of our stock and future transactions, including potential equity issuances and liability management efforts could ultimately result in another “ownership change” occurring in the future. Under section 382 of the Code, absent an applicable exception, if a corporation undergoes an” ownership change,” the amount of its pre-“ownership change” NOLs and other tax attributes that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the “ownership change” multiplied by the long-term tax-exempt rate, plus, if we have a so-called “net unrealized built-in gain” in our assets, an additional amount calculated based on certain actual or “deemed” “recognized” “built-in gains” in our assets that occur within a 5-year “recognition period” following an “ownership change.” By contrast, in the event we were to determine that we will have a so-called “net unrealized built-in loss” in our assets at the time an “ownership change” occurs, our “recognized built-in losses” during the 5-year “recognition period” would also become subject limitation. The IRS has proposed regulations that would substantially change the calculations regarding “net unrealized built-in gains,” “recognized built-in gains,” “net unrealized built-in losses,” and “recognized built-in losses” in a way that is highly taxpayer-unfavorable, but we cannot predict when and to what extent those proposed regulations will be finalized. The ownership change that occurred as a result of our exit from chapter 11 proceedings should not materially limit our ability to utilize our NOL carryforwards, but it may be affected by future “ownership changes”. In addition, under the tax reform bill commonly as the Tax Cuts and Jobs Act (the “Tax Act”), which was signed into law on December 22, 2017, (i) the amount of post-2017 NOLs that we are permitted to deduct in any taxable year was generally limited to 80% of our taxable income in such year, where taxable income is determined without regard to the NOL deduction itself, and (ii) post-2017 net operating losses were not able to be carried back to prior taxable years. However, utilization of net operating losses has been temporarily expanded under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). Under the CARES Act, (i) for taxable years beginning before 2021, NOL carryforwards and NOL carrybacks may offset 100% of taxable income, and (ii) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the five preceding years to generate a refund. There can be no assurance that we will be able to utilize our U.S. federal income tax NOL carryforwards to offset future taxable income.

Our operations and liquidity could be adversely affected if we fail to maintain required bonds or if surety companies require us to secure such bonds with cash collateral or letters of credit.

Federal and state laws require bonds or cash deposits to secure our obligations with respect to various parts of our operations. Our failure to maintain, or inability to acquire, bonds that are required by state and federal law would have a material adverse effect on us. That failure could result from a variety of factors including: (i) our failure to comply with rules and regulations of federal and state governmental agencies, including the BLM, (ii) the lack of availability of bonding, higher expense or unfavorable market terms of new bonds; and (iii)  the exercise by third-party bond issuers of their right to refuse to renew the bonds. If we fail to maintain required bonds, our production may significantly decrease, which would significantly decrease our already constrained cash flow.   In addition, surety companies may require us to post letters of credit or secure bonds with cash collateral as a result of our credit rating, which would adversely affect our liquidity.

 

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Liquidity concerns could result in 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 is, 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, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.

We cannot control the future price of oil and natural gas and sustained periods of low prices could hurt our profitability and financial condition and could impair our ability to grow our business or to perform the obligations in our agreements, including the agreements governing our indebtedness.

Sustained periods of low commodity prices will adversely affect our operations and financial condition. Our revenues, profitability, liquidity, ability to raise capital for our business, future growth, ability to operate, develop and explore our properties, and the carrying value of our properties depend heavily on prevailing prices for oil and natural gas.

Natural gas comprised approximately 96% of our total production and 86% of our consolidated revenue for the year ended December 31, 2019 and represented 96% of our total proved reserves as of December 31, 2019. Historically, natural gas prices have been highly volatile, including in the Rocky Mountain region of the United States where the vast majority of our natural gas is produced. Prices have been affected by actions of federal, state and local governments and agencies, foreign governments, national and international economic and political conditions, levels of consumer demand, weather conditions, domestic and foreign supply of oil and natural gas, proximity and capacity of gas pipelines and other transportation facilities, the price and availability of equipment, materials and personnel to conduct operations, and the price and availability of alternative fuels. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of natural gas. Any substantial or extended decline in the price of natural gas will have a material adverse effect on our financial condition and results of operations, including reduced cash flow and borrowing capacity, and lower proved reserves. Price volatility also makes it difficult to budget for and project the return on potential acquisitions and development and exploration projects, and sustained lower gas prices have caused and may, in the future continue to cause, us or the operators of properties in which we have ownership interests to curtail projects and limit or suspend drilling, completion or even production activities.

Crude oil comprised approximately 4% of our total production and 13% of our consolidated revenue for the year ended December 31, 2019 and represented 4% of our total proved reserves as of December 31, 2019. In the future, crude oil prices may remain at current levels or fall to lower levels. If crude oil prices remain at current levels or fall to lower levels, this will adversely affect our crude oil operations and our financial condition.

In addition, because we are significantly leveraged, a substantial decrease in our revenue due to low commodity prices is currently impairing and may in the future continue to impair our ability to satisfy payment obligations on our indebtedness and reduce funds available for operations and future business opportunities.

A substantial or extended decline in oil and natural gas prices may continue indefinitely, and may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations, our debt repayment and service obligations, and our financial commitments.

The price we receive for our oil and natural gas heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and we expect this volatility to continue for the foreseeable future. For example, during the period from January 1, 2014 to December 31, 2019, the Calendar month average of NYMEX West Texas Intermediate oil prices ranged from a high of $105.15 per Bbl to a low of $30.62 per Bbl. NYMEX Natural Gas settlement prices have ranged from a high of $5.56 per MMBtu to a low of $1.71 per MMBtu during the same period. Additionally, the price differential for natural gas can also vary significantly. Over this same period, monthly prices for NwRox ranged from a high of $5.70 per MMBtu to a low of $1.51 per MMBtu. This near-term volatility may affect future prices in 2020 and beyond. The volatility of the energy markets makes it difficult to predict future oil and natural gas price movements with any certainty.

The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

 

worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

 

the actions of the Organization of Petroleum Exporting Countries (“OPEC”);

 

the price and quantity of imports of foreign oil and natural gas;

 

political conditions in or affecting other oil and natural gas-producing countries;

 

the level of global oil and natural gas exploration and production;

 

the level of global oil and natural gas inventories;

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localized supply and demand fundamentals and transportation availability;

 

weather conditions and natural disasters;

 

government policies to discourage use of fuels that emit “greenhouse gases” (“GHGs”) and encourage use of alternative energy;

 

domestic, local and foreign governmental regulations and taxes;

 

speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

 

price and availability of competitors’ supplies of oil and natural gas;

 

technological advances affecting energy consumption;

 

the availability of drilling rigs and completion equipment; and

 

the overall economic environment.

Substantially all of our production is currently sold at market-based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. Lower oil and natural gas prices will reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations, and, may cause us to make significant downward adjustments to our estimated proved reserves or to be unable to claim proved undeveloped reserves at all. If oil and natural gas prices remain at current levels or experience a substantial or extended decline from current levels, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures will be materially and adversely affected.

Our reserve estimates may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, drilling, testing and production data acquired subsequent to the date of an estimate may justify revising such estimates. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, the timing and identification of future drilling locations, commodity prices, future production levels, costs and the ability to finance future development that may not prove correct over time. Predictions of future production levels, development schedules (particularly with regard to non-operated properties), participation of joint working interest owners on projects, commodity prices and future operating costs are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based.

The present value of net proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. In accordance with SEC requirements, we base the present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves on the average oil and natural gas prices during the 12-month period before the ending date of the period covered by this report determined as an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for quality and transportation fees. The costs to produce the reserves remain constant at the costs prevailing on the date of the estimate. Actual current and future commodity prices and costs may be materially higher or lower, and higher future costs and/or lower future commodity prices may impact whether development of our reserves in the future occurs as scheduled or at all. In addition, the 10% discount factor, which the SEC requires us to use in calculating our discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on our cost of capital from time to time and/or the risks associated with our business.

Our producing properties are located in the Green River Basin in southwest Wyoming, making us vulnerable to risks associated with operating in a single geographic area.

All of our producing properties are geographically concentrated in the Green River Basin in southwest Wyoming. At December 31, 2019, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we are disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought-related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

Competitive industry conditions may negatively affect our ability to conduct operations.

We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and natural gas companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a

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greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.

Factors that affect our ability to compete in the marketplace include:

 

our access to the capital necessary to drill and complete wells and acquire properties;

 

our ability to acquire and analyze seismic, geological and other information relating to a property;

 

our ability to attract and retain the personnel necessary to properly evaluate seismic and other information relating to a property;

 

our ability to procure materials, equipment and services required to explore, develop and operate our properties;

 

our ability to comply with administrative, regulatory and other governmental requirements; and

 

our ability to access pipelines, and the locations of facilities used to produce and transport oil and natural gas production.

Factors beyond our control affect our ability to effectively market production and may ultimately affect our financial results.

The ability to market oil and natural gas depends on numerous factors beyond our control. These factors include:

 

the extent of domestic production and imports of oil and natural gas;

 

the availability of pipeline, rail and refinery capacity, including facilities owned and operated by third parties;

 

the availability of a market for our oil and natural gas production;

 

the availability of satisfactory transportation arrangements for our oil and natural gas production;

 

the proximity of natural gas production to natural gas pipelines;

 

the effects of inclement weather;

 

the demand for oil and natural gas by utilities and other end users;

 

the availability of alternative fuel sources;

 

state and federal regulations of oil and natural gas marketing and transportation; and

 

federal regulation of natural gas sold or transported in interstate commerce.

Because of these factors and other factors beyond our control, we may be unable to market all of the oil and natural gas that we produce or obtain favorable prices for such production.

Our business relies on certain key personnel.

Our management believes that our continued success will depend to a significant extent upon the efforts and abilities of certain of our key personnel. The loss of the services of any of these key personnel could have a material adverse effect on our business. We do not maintain “key man” life insurance on any of our officers or other employees.

Any derivative transactions we enter into may limit our gains and expose us to other risks such as taxes and royalties.

We may enter into financial derivative transactions from time to time to manage our exposure to commodity price risks. These transactions limit our potential gains if commodity prices rise above the levels established by our derivative transactions. These transactions may also expose us to other risks of financial losses, for example, if our production is less than we anticipated at the time we entered into a derivative instrument or if a counterparty to our derivative instruments fails to perform its obligations under a derivatives transaction.  We pay royalties and taxes based on physical production; therefore, if we have utilized derivative transactions on a high percentage of our forecast production, we may have royalty and tax burdens that are significantly higher than the derivative price settled for that month’s production.  

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Legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd–Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.

Although the CFTC has issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from those position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions.

While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits, depending on the Company’s ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require us to comply with position limits in connection with our financial derivative activities. The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC on our business will not be known until all of the rules to be adopted under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

Compliance with environmental and occupational safety and health laws and other government regulations could be costly and could negatively impact our production.

Our operations are subject to numerous and complex laws and regulations relating to occupational safety and health aspects of our operations and protection of the environment. These laws and regulations, which are continuously being reviewed for amendment and/or expansion, may:

 

require that we acquire permits before developing our properties;

 

restrict the substances that can be released into the environment in connection with drilling, completion and production activities;

 

limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; and

 

require remedial measures to mitigate pollution from former operations, including plugging previously abandoned wells.

Under these laws and regulations or under the common law, we could be liable for personal injury and clean-up costs and other environmental, natural resource and property damages, as well as administrative, civil and criminal penalties or injunctions. Failure to comply with these laws and regulations could also result in the occurrence of delays or restrictions in permitting or performance of projects, or the issuance of orders and injunctions limiting or preventing operations relating to our properties in some areas. Under certain environmental laws and regulations, an owner or operator of our properties could be subject to strict, joint and several liability for the investigation, removal or remediation of previously released materials or property contamination. Liability may be imposed regardless of whether the owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred. Private parties, including the owners of properties upon which wells are drilled or facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, to seek damages for contamination or for personal injury or property damage. We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by accidental environmental damages. Accordingly, we may be subject to liability in excess of our insurance coverage or may be required to curtail or cease production from properties in the event of material environmental damages.

We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, greenhouse gases and hydraulic fracturing. Changes in environmental laws and regulations occur frequently, and these changes could result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation or disposal, emission or discharge requirements. Any such changes could require significant expenditures by the Company or other operators of the properties to attain and maintain compliance and may otherwise have a material adverse effect on the results of operations, competitive position or financial condition of the Company or such other operators. The oil and natural gas industry faced increased scrutiny as a result of the FY 2017-2019 National Enforcement Initiatives (“NEI”) promulgated by the EPA, through which the EPA purportedly sought to address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment. However, in June 2019, EPA proposed to transition its focus to significant public health and environmental problems without regard to sector, renaming the NEI program and issuing the FY 2020-2023 National Compliance Initiatives, thereby discontinuing the energy extraction activities NEI. Government disruptions, such as an extended federal government shutdown resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits, approvals, and certificates required to conduct our operations.

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A significant percentage of our operations are conducted on federal and state lands. These operations are subject to a wide variety of regulations as well as other permits and authorizations which must be obtained from and issued by state and federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Complying with any of these requirements may adversely affect our ability to complete our drilling programs at the costs and in the time periods anticipated.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and gas we produce.

More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply with such laws and regulations. In the absence of comprehensive federal legislation on GHG emission control, the EPA requires the permitting of GHG emissions for certain sources that require permits due to emissions of other pollutants. The EPA also requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis. We will continue to incur costs associated with this reporting obligation.

In May 2016, the EPA finalized rules to reduce methane emissions and VOC from new, modified or reconstructed sources in the oil and natural gas sector; however, in September 2018, under a new administration, the EPA proposed amendments that would relax requirements of the rules. In August 2019, the EPA proposed a significant rollback to the 2016 rule that, if finalized, would rescind the VOC and methane requirements applicable to transmission and storage sources and the methane requirements for production and processing sources, or in the alternative, rescind methane requirements applicable to all oil and natural gas sources. Additionally, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it previously enacted to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands; California and New Mexico have challenged the new rule in ongoing litigation.  In addition, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending (as of October 2019, the EPA had requested a stay of the litigation pending its proposed overhaul of the 2016 methane requirements). Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category.  

In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states and regions have already taken legal measures to reduce or measure GHG emission levels, often involving the planned development of GHG emission inventories and/or regional cap and trade programs. Most of these cap and trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to reduce overall GHG emissions. The cost of these allowances could escalate significantly over time. In addition, there are Congressional proposals that could result in significant curtailment of oil and natural gas development and production, and hydraulic fracturing in particular, on BLM lands, where we hold considerable acreage. On an international level, almost 200 nations agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although the present administration has announced its intention to withdraw from the Paris accord, several states and local governments remain committed to its principles in their effectuation of policy and regulations. It is not possible at this time to predict if, how or when the United States or states might impose restrictions on GHGs as a result of the international climate change agreement. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.  

Moreover, incentives to conserve energy, reduce greenhouse gas emissions in product supply chains, or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in or lending to oil and natural gas activities. Finally, growing 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.

Potential physical effects of climate change could adversely affect our operations and cause us to incur significant costs in preparing for or responding to those effects.

Most scientists have concluded that increasing concentrations of GHG in the atmosphere may produce significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events, that could have an adverse effect on our operators’ operations and the production on our properties. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies, suppliers, or customers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including with respect to water use and waste disposal, could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions; however, the EPA has taken certain actions with respect to regulating hydraulic fracturing. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in 2012 and additional CAA regulations in May 2016 governing performance standards for the oil and natural gas industry, for which the EPA in August 2019 has proposed amendments that would rescind certain requirements of the regulations; issued in June 2016 final effluent limitations guidelines under the CWA that waste water from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, following years of litigation, the BLM rescinded the rule in December 2017; a lawsuit challenging the rule rescission is pending. The BLM also issued rules in November 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands, although the present administration is proposing to delay the implementation dates applicable to the requirements under these rules. The BLM also issued rules in November 2016 to limit methane emissions from new and existing oil and gas operations on federal lands, but subsequently relaxed and rescinded certain requirements of the rules in September 2018; a lawsuit challenging the September 2018 rule revision is pending.

From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Wyoming has adopted regulations requiring producers to provide detailed information about wells they hydraulically fracture in that state. Some states have adopted or are considering adopting regulations requiring disclosure of chemicals in fluids used in hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. We have conducted hydraulic fracturing operations on most of our existing wells, and we anticipate conducting hydraulic fracturing operations on substantially all of our future wells. As a result, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities and adversely affect our operations and financial condition.

In addition, hydraulic fracturing operations require the use of a significant amount of water. The inability to locate sufficient amounts of water, or dispose of or recycle water used in drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

Finally, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes.  In Oklahoma, for example, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity.  Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Although our operations are not located in those jurisdictions, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations.

Changes in tax laws and regulations, including interpretations thereof, or in our operations may impact our effective tax rate and may adversely affect our business, financial condition and operating results.

Tax interpretations, regulations, and legislation in the various jurisdictions in which we and our affiliates operate are subject to measurement uncertainty and the interpretations can impact net income, income tax expense or recovery, and deferred income tax assets or liabilities.  In addition, tax rules and regulations, including those relating to foreign jurisdictions, are subject to interpretation and require judgment by us that may be challenged by the taxation authorities upon audit.  In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the Tax Act, and the CARES Act, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. Changes in tax laws in any of the multiple jurisdictions in which we operate could result in an unfavorable change in our effective tax rate or timing of payments that we are obligated to make, either of which could adversely affect our business, financial condition, and operating results.

On March 27, 2020, President Trump signed into U.S. federal law the CARES Act, which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security

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payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, under the CARES Act, (i) for taxable years beginning before 2021, net operating loss carryforwards and carrybacks may offset 100% of taxable income, (ii) NOLs arising in 2018, 2019, and 2020 taxable years may be carried back to each of the preceding five years to generate a refund and (iii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased from 30% to 50% of EBITDA. We are analyzing the different aspects of the CARES Act to determine whether any specific provisions may impact us.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies, including technologies operated by or under the control of third parties, to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Unauthorized access to (or the loss of Company access to) our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While our operations and financial condition have not been materially and adversely affected by cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Our business and the trading prices of our securities could be negatively impacted by the actions of so-called “activist” stockholders.

If we become the subject of activity by activist shareholders, this could disrupt our business, distract our management and board of directors, and negatively impact our business and the trading prices of our securities, including our common shares. Responding to shareholder activism can be costly and time-consuming, disrupt our operations, and divert the attention of management and our employees from our strategic initiatives. Furthermore, activist campaigns can create perceived uncertainties as to our future direction, strategy, or leadership and may result in the loss of potential business opportunities, harm our ability to attract new employees, investors, customers, and joint venture partners, and cause our stock price to experience periods of volatility.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit in the European, Asian and the U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, NGL and natural gas, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which oil, NGL and natural gas from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

If a sustained financial or economic downturn occurs domestically or internationally, capital market conditions and commodity prices may deteriorate, which could materially and adversely affect our liquidity, results of operations and ability to execute our business.

Global and domestic economic conditions are difficult for us to forecast and impossible for us to control. Similarly, conditions in global and domestic capital markets, including debt and equity markets, are difficult for us to forecast and impossible for us to control. Adverse changes, even material adverse changes, in global and domestic economic conditions and in domestic and international capital markets may occur without warning. Although there are steps we can take to anticipate and mitigate such changes, we may fail to do so. If we fail to successfully anticipate or mitigate such matters, adverse changes in global or domestic economic conditions or capital markets, especially materially adverse changes, could increase our costs, limit our financial flexibility, and materially and adversely affect our business, results of operations, and liquidity.  

Outbreaks of communicable diseases could adversely affect our business, financial condition and results of operations.

Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks on a global basis, including in the United States, of COVID-19. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. Additionally,

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if a pandemic or epidemic, including COVID-19, were to impact a location where we have a high concentration of our business and resources, the workforce we depend on could be affected by such occurrence, which could also significantly disrupt our results of operations. The duration of such a disruption and the related financial impact from COVID-19 and other such pandemics cannot be reasonably estimated at this time. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition and results of operations.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts. However, these negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed oil production cuts will expire on April 1, 2020. These actions led to an immediate and steep decrease in oil prices. There can be no assurance that OPEC members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition and results of operations.

Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time.

Our future success depends on our ability to find, acquire, develop and produce additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, our reserves and production will decline. As we assess our business operations in light of our need for liquidity and the current natural gas price environment, we currently have no immediate plans to drill additional wells in our leasehold position in the Green River Basin in southwest Wyoming.  This suspension of drilling activity will lead to a decline in our reserves as has been evidenced by our decision to suspend drilling operations in September 2019, due to the low commodity price environment and the expected investment returns in the current commodity price environment.  We can give no assurance that we will be able to find, develop or acquire additional reserves at acceptable costs or at all.

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capital expenditures to develop our existing reserves and to discover new oil and gas reserves.

Our ability to resume exploration and development of our properties and to replace reserves depends upon our ability to comply with our debt covenants, renegotiate our debt agreements, raise significant additional financing, or to seek and obtain other arrangements with industry participants in lieu of raising additional financing. Any arrangements that may be entered into could be expensive to us if such arrangements can be made at all. There can be no assurance that we will be able to raise additional capital in light of factors such as our financial condition, the market demand for our securities, the general condition of financial markets for independent oil and gas companies (including the markets for debt), oil and natural gas prices and general market conditions. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of our capital budget. Continued periods of depressed commodity prices or further commodity price decreases could have a material adverse effect on our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. There can also be no assurance that we will be able to obtain other satisfactory arrangements to allow further exploration and development of our properties if we are unable to raise additional capital.

We expect to use our cash from operations, cash from draws on the Revolving Credit Facility and cash on hand to fund our capital budget, our operating costs and our interest service obligations during 2020.  The loan commitment and the aggregate amount of money that we can borrow under the Revolving Credit Facility and from other sources is revised from time to time based on certain restrictive covenants.  A change in our ability to meet the restrictive covenants may limit our ability to borrow.  If this occurred, we may have to sell assets or seek substitute financing.  We can make no assurances that we would be successful in selling assets or arranging substitute financing. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for information about our liquidity, available cash on hand, and the description of the current debt agreements.

Our operations may be interrupted by severe weather or drilling restrictions.

Our operations are conducted exclusively in the Rocky Mountain region of the United States. The weather in this area can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Likewise, our operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.

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We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

The oil and natural gas business involves a variety of operating risks, including blowouts, fire, explosion, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, natural gas leaks, discharges of toxic gases, underground migration and surface spills or mishandling of fracture fluids, including chemical additives. The occurrence of any of these events with respect to any property we own or operate (in whole or in part) could have a material adverse impact on us. We and the operators of our properties maintain insurance in accordance with customary industry practices and in amounts that management believes to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial condition.

There are risks associated with our drilling activity that could impact our results of operations.

Our oil and natural gas operations are subject to all of the risks and hazards typically associated with drilling, completion, production and transportation of, oil and natural gas. These risks include the necessity of spending large amounts of money for identification and acquisition of properties and for drilling and completion of wells. In the drilling and completing of wells, failures and losses may occur before any deposits of oil or natural gas are found and produced. The presence of unanticipated pressure or irregularities in formations, blow-outs or accidents may cause such activity to be unsuccessful, resulting in a loss of our investment in such activity and possible liabilities. If oil or natural gas is encountered, there can be no assurance that it can be produced in quantities sufficient to justify the cost of continuing such operations or that it can be marketed satisfactorily.

Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all.

A prospect is an area in which our geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill our prospects depends on many factors, including but not limited to: the availability and cost of capital; receipt of additional seismic data or reprocessing of existing data; material changes in current of future expected oil or natural gas prices; the costs and availability of drilling and completion equipment; the success or failure of wells drilled in similar formations or which would use the same production facilities and equipment; changes in the estimates of costs to drill or complete wells; decisions of our joint working interest owners; and regulatory, permitting and other governmental requirements. It is possible these factors and others may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all.

We have limited control over activities conducted on properties we do not operate.

We own interests in properties that are operated by third parties. The success, timing and costs of drilling, completion, and other development activities on our non-operated properties depend on a number of factors that are beyond our control. Because we have only a limited ability to influence and control the operations of our non-operated properties, we can give no assurances that we will realize our targeted returns with respect to those properties.

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas that we produce.

The marketability of our oil and natural gas production will depend in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations, financial condition and prospects.

We may fail to fully identify problems with any properties we acquire.

We acquired a portion of our acreage position through property acquisitions and acreage trades, and we may acquire additional acreage in these or other regions in the future. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify.

Our acquisitions may perform worse than we expected or prove to be worth less than what we paid because of uncertain factors and matters beyond our control. In addition, our acquisitions could expose us to potentially significant liabilities.

When we make acquisitions of oil and gas properties, we make assumptions about many uncertain factors, including estimates of recoverable reserves, expected timing of recovering acquired reserves, future commodity prices, expected development and operating costs,

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and other matters, many of which are beyond our control. Assumptions about uncertain factors may be wrong, and the properties we acquire may perform worse than we expect, materially and adversely affecting our operations and financial condition.

Conservation measures and improvements in or new discoveries of alternative technologies could have a material adverse effect on our financial condition and results of operations.

Since our business depends on the level of activity in the oil and natural gas industry, any fuel conservation measures, improvement in or new discoveries of alternative energy, transportation, or materials technologies and increasing consumer demand for alternatives to oil and natural gas that increase the use of alternative forms of energy and alternative feedstocks, and reduce the demand for oil and natural gas could have a material adverse effect on our business, financial condition, and operations.

Any future implementation of price controls on oil and natural gas would affect our operations.

The United States Congress may in the future impose some form of price controls on either oil, natural gas, or both. Any future limits on the price of oil or natural gas could negatively affect the demand for our services and consequently, have a material adverse effect on our business, financial condition, and results of operations.

A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital.

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects.

Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards 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 energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.

A low ESG or sustainability score could result in the exclusion of our common shares from consideration by certain investment funds and a negative perception of us by certain investors.

Certain organizations that provide corporate governance and other corporate risk information to investors and shareholders have developed scores and ratings to evaluate companies and investment funds based upon environmental, social and governance (“ESG”) or “sustainability” metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Many investment funds focus on positive ESG business practices and sustainability scores when making investments. In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of the Company’s common shares from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of the Company by certain investors.

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Damage to our reputation could damage our business.

Our reputation is a critical factor in our relationships with employees, investors, customers, suppliers and joint venture partners. If we fail to address, or appear to fail to address, issues that give rise to reputational risk, including those described throughout this “Risk Factors” section, we could significantly harm our reputation. Our reputation may also be damaged by how we respond to corporate crises. Corporate crises can arise from catastrophic events as well as from incidents involving unethical behavior or misconduct; allegations of legal noncompliance; internal control failures; corporate governance issues; data breaches; workplace safety incidents; environmental incidents; media statements; the conduct of our suppliers or representatives; and other issues or incidents that, whether actual or perceived, result in adverse publicity. If we fail to respond quickly and effectively to address such crises, the ensuing negative public reaction could significantly harm our reputation and could lead to increases in litigation claims and asserted damages or subject us to regulatory actions or restrictions.

Damage to our reputation could negatively affect the demand for our services and consequently, have a material adverse effect on our business, financial condition, and results of operations. It could also reduce investor confidence in us, adversely affecting our stock price. Moreover, repairing our reputation may be difficult, time-consuming and expensive.

We are a smaller reporting company, and we cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.

We are currently a “smaller reporting company,” meaning that we are not an investment company, an asset- backed issuer, or a majority-owned subsidiary of a parent company that is not a smaller reporting company and have a non-affiliated public float of less than $250 million or annual revenues of less than $100 million and public float of less than $700 million during the most recently completed fiscal year. At such time as we cease being a “smaller reporting company,” we will be required to provide additional disclosure in our SEC filings. “Smaller reporting companies” are able to provide simplified disclosures in their filings, including with respect to, among other things, executive compensation and financial statement information and are also exempt from certain provisions of the Sarbanes-Oxley Act which may make it harder for investors to analyze our results of operations and financial prospects.

Forward-Looking Statements

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), Section 21E of the Exchange Act, and the Private Securities Litigation Reform Act of 1995. Except for statements of historical facts, all statements included in this document, including those statements preceded by, followed by or that otherwise include the words “believe,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct.

Forward-looking statements include statements regarding:

 

our oil and natural gas reserve quantities, and the discounted present value of those reserves;

 

the amount and nature of our capital expenditures;

 

drilling of vertical and horizontal wells;

 

the timing and amount of future production and operating costs;

 

our ability to respond to low natural gas prices;

 

our levels of indebtedness

 

business strategies and plans of management; and

 

prospect development and property acquisitions.

Some of the risks which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include:

 

volatility and, especially, declines or substantial declines and weakness in natural gas or oil prices;

 

our ability to maintain adequate liquidity in view of current natural gas prices or following the recent default under the terms of our Credit Agreement and Term Loan Agreement resulting from the going concern qualification to our audited, consolidated financial statements in this Form 10-K;

 

our ability to comply with the covenants and restrictions of the agreements governing our indebtedness, or our ability to amend or replace the agreements governing our indebtedness;

 

the uncertainty of estimates of oil and natural gas reserves such that our estimates of oil and natural gas reserve quantities, and the discounted present value of those reserves may change for a variety of reason including but not limited to changes in prices, costs, estimated decline curves, among other circumstances;

 

our ability to restructure our balance sheet in a manner that allows us to continue as a going concern over the long term;

 

changes in taxation laws in local and state jurisdictions;

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any future global economic downturn;

 

the impact of outbreaks of communicable diseases such as the novel highly transmissible and pathogenic coronavirus (“COVID-19”) on business activity, the Company’s operations and national and global economic conditions, generally;

 

the willingness of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels;

 

general economic conditions, including the availability of credit and access to existing lines of credit;

 

conditions in capital markets, including the availability of capital to companies in the oil and gas business;

 

the volatility of oil and natural gas prices;

 

the impact of competition;

 

the availability and cost of seismic, drilling and other equipment;

 

our decisions about how we allocate capital and resources among strategic opportunities;

 

operating hazards inherent in the exploration for and production of oil and natural gas;

 

difficulties encountered during the exploration for and production of oil and natural gas;

 

difficulties encountered in delivering oil and natural gas to commercial markets;

 

the impact of our shares trading on the OTC Bulletin Board;

 

our ability to maintain the listing of our common shares on The OTCQX tier of the OTC Bulletin Board;

 

changes in customer demand and producers’ supply;

 

the uncertainty of our ability to attract capital and obtain financing on favorable terms;

 

negative shifts in investor sentiment of the oil and gas industry;

 

negative public perception regarding us and/or our industry;

 

reductions in our borrowing base under our Revolving Credit Facility;

 

compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business, including those related to climate change and greenhouse gases, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and the use of water, and financial derivatives and hedging activities;

 

actions of operators of our oil and natural gas properties; and

 

weather conditions.

The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could affect our operating results and performance. We urge you to carefully consider these factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made, and we have no obligation to update these forward-looking statements.

Item 1B.

Unresolved Staff Comments.

None.

Item 2.     Properties.

Location and Characteristics

The Company owns oil and natural gas leases in Wyoming.  The leases in Wyoming are primarily federal leases with 10-year lease terms until establishment of production. Production extends the lease terms until cessation of that production. The Company previously owned oil and natural gas leases in Utah and Pennsylvania, which the Company sold in September 2018 and December 2017, respectively.

Due to the cessation of the drilling program, the Company has no estimated PUD reserves as of December 31, 2019, with respect to its properties because it has elected not to drill new wells in the current commodity price environment. Additionally, as noted below, the Company’s has a $5 million limitation of capital expenditures per quarter as set forth in the Fifth Amendment to the Credit Agreement. The Company previously reported estimated PUD reserves in SEC filings, and, if in the future we can satisfy the reasonable certainty criteria as prescribed under the SEC requirements, we would likely record and report estimated PUD reserves in future filings.

Green River Basin, Wyoming

Acreage. As of December 31, 2019, the Company owned oil and natural gas leases totaling approximately 117,000 gross (83,000 net) acres in southwest Wyoming’s Green River Basin. Most of this acreage covers the Pinedale and Jonah fields. Of the total acreage position in Wyoming and as of December 31, 2019, approximately 45,000 gross (30,000 net) acres were developed, and 72,000 gross (53,000 net) acres

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were undeveloped. The developed and undeveloped portion represents 100% of the Company’s total developed and undeveloped net acreage. The Company operates 92% of its production in the Pinedale field.

Lease maintenance costs in Wyoming were approximately $0.7 million for the year ended December 31, 2019. The Company currently owns 51 leases totaling 79,000 gross (54,000 net) acres that are held by production and activities (“HBP”). The HBP acreage includes all of the Company’s leases within the productive area of the Pinedale and Jonah fields.

Development Wells.  Development wells are wells that were drilled in the current year that were proved undeveloped locations in the prior year’s reserve report.  During 2019, the Company participated in the drilling of 64.0 gross (51.0 net) productive development wells on the Green River Basin properties.  At December 31, 2019, the Company did not have any additional development wells that commenced during the year and were either still drilling or had operations suspended at a depth short of total depth.

Exploratory Wells.  Exploratory wells are wells that were drilled in the current year that were not proved undeveloped locations in the prior year’s reserve report.  During 2019, the Company participated in the drilling of a total of 20.0 gross (20.0 net) productive exploratory wells on the Green River Basin properties. At December 31, 2019, there were 9.0 gross (3.8 net) exploratory wells which were suspended at a depth short of total depth and thus a determination of productive capability could not be made at year-end.

Seismic Activity.     The Company owns 492 square miles of 3D seismic data in Wyoming which provides 455 square miles of coverage of the entire Pinedale Anticline and most of Jonah field. The data consists of proprietary data and data licensed from seismic contractors. During 2019, the Company completed a 40 square mile seismic inversion project to enhance the resolution and illuminate the sandstones in the Lower Lance and Mesaverde in the southern Anticline area to assist with future wellbore targeting. The Company also completed a 95 square mile 3D structural reconstruction study of the middle portion of the Pinedale Anticline that elucidates the geological structural history, trapping geometry, and fluid migration to explain variations in hydrocarbon accumulation and assist with future well planning.

Divested Assets

Uinta Basin, Utah.  During the third quarter 2018, the Company sold the oil and gas properties covering approximately 8,300 gross (7,800 net) acres in the Uinta Basin in Utah for net cash proceeds of $69.3 million, including transaction fees of $0.6 million. This acreage is located in Uintah County in the eastern portion of the Uinta Basin.

Pennsylvania.  During the fourth quarter of 2017, the Company sold the oil and gas leases covering 144,000 gross (72,000 net) acres in the Pennsylvania portion of the Appalachian Basin for a cash purchase price of approximately $115.0 million.

Oil and Gas Reserves

The following table sets forth the Company’s quantities of proved reserves for the years ended December 31, 2019, 2018 and 2017. The reserve estimates were prepared by Netherland, Sewell & Associates, Inc.  The table summarizes the Company’s proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2019, 2018 and 2017.

In 2017, the Company renegotiated its existing gas processing contracts in Wyoming. These gas processing contracts are keep-whole contracts in which the Company shares in the economic benefit of processing and accordingly does not include the NGL volumes in its reserves.

The Company’s internal controls for booking PUD reserves include testing whether the Company has the intent and financial capability to execute PUD drilling. During 2019, the Company decided to suspend its operated drilling program in the Pinedale field.  This decision was based on natural gas pricing remaining near multi-year lows.  As such, the Company lacks the required degree of certainty of our ability commit resources to fund the drilling of new wells in our five-year development program. As a result, we did not record any PUD reserves in the December 31, 2019 reserve report. As of December 31, 2018 and 2017, proved undeveloped reserves represented 23% of the Company’s total proved reserves.  

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December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

($ amounts in thousands, except per unit data)

 

Proved Developed Reserves

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

1,902,600

 

 

 

2,243,956

 

 

 

2,261,289

 

Oil (MBbl)

 

 

14,627

 

 

 

17,876

 

 

 

21,652

 

Natural gas liquids (MBbl)

 

 

 

 

 

 

 

 

71

 

Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

 

 

 

677,877

 

 

 

694,703

 

Oil (MBbl)

 

 

 

 

 

5,569

 

 

 

5,466

 

Natural gas liquids (MBbl)

 

 

 

 

 

 

 

 

 

Total Proved Reserves (MMcfe) (1)

 

 

1,990,362

 

 

 

3,062,503

 

 

 

3,119,126

 

Estimated future net cash flows, before income tax

 

$

2,904,393

 

 

$

4,724,843

 

 

$

4,377,344

 

Discounted future net cash flows, before income taxes (2)

 

$

1,710,619

 

 

$

2,435,356

 

 

$

2,384,328

 

Future income tax (discounted)

 

$

 

 

$

(29,873

)

 

$

 

Standardized measure of discounted future net cash flows, after income tax

 

$

1,710,619

 

 

$

2,405,483

 

 

$

2,384,328

 

Calculated average price (3)

 

 

 

 

 

 

 

 

 

 

 

 

Gas ($/Mcf)

 

$

2.44

 

 

$

2.59

 

 

$

2.59

 

Oil ($/Bbl)

 

$

55.36

 

 

$

63.49

 

 

$

48.05

 

NGLs ($/Bbl)

 

$

 

 

$

 

 

$

26.85

 

 

(1)

Oil, condensate and NGLs are converted to natural gas at the ratio of one barrel of liquids to six Mcf of natural gas. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or condensate to an Mcf of natural gas.

(2)

Management believes that the presentation of the discounted future net cash flows, before income taxes, of estimated proved reserves, discounted at 10% per annum, may be considered a non-Generally Accepted Accounting Principle financial measure as defined in Item 10(e) of Regulation S-K, therefore the Company has included this reconciliation of the measure to the most directly comparable Generally Accepted Accounting Principle (“GAAP”) financial measure (standardized measure of discounted future net cash flows, after income taxes). Management believes that the presentation of the standardized measure of future net cash flows before income taxes provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of the Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies. The standardized measure of discounted future net cash flows, before income taxes, is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. Standardized measure of discounted future net cash flows, before income taxes, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

(3)

As prescribed by SEC rules, our reserve estimates at December 31, 2019, 2018 and 2017, reflect reference pricing based on the average of the monthly prices during the 12-month period before the ending date of the period covered by this report determined as an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period.

Since January 1, 2016, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

Proved Undeveloped Reserves

As previously mentioned, the Company did not include PUD reserves in its total proved reserve estimates as of December 31, 2019 due to its decision to suspend its operated drilling program.

Development plan:    The development plan underlying the Company’s PUD reserves, if any, is based on the best information available at the time of adoption. Factors, such as commodity price, service costs, performance data, and asset mix, are subject to change; therefore, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals, and substitutions of previously scheduled PUD reserve locations.

As commodity prices fell during 2019, management and the Board revised the development plan and decreased the development pace.  Over the course of 2019, we decreased our drilling program reducing the number of rigs deployed in development from three to two, then to one, and ultimately to zero.  Despite the reduction of activity, the Company’s PUD conversion rate was 19.8% in 2019.

In addition, as a part of our internal controls for determining a plan to develop our proved reserves each year, we consider whether we have the intent and financial capability to develop PUD reserves. This year, because of the natural gas price environment and the projected investment returns, we lack the required degree of certainty that we have the ability to fund a development plan. Therefore, as of December 31, 2019, we transferred all of our PUD reserves to unproved status. We anticipate reporting PUD reserves in future filings, if we determine that we have the intent and financial capability to execute a development plan.

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Changes in proved undeveloped reserves:    The Company annually reviews all PUD reserves to ensure an appropriate plan for development exists.  Changes to the Company’s PUD reserves during 2019 are summarized in the table below.  These changes include updates to prior PUD reserves, the transfer and revision of PUD reserves to unproved categories due to development plan changes, and the impact of changes in economic conditions, including changes in commodity prices.  

 

 

 

MMcfe

 

Proved undeveloped reserves, December 31, 2018

 

 

711,293

 

Converted to proved developed

 

 

(140,929

)

Proved undeveloped reserve extensions

 

 

 

Proved undeveloped reserve purchased

 

 

 

Proved undeveloped reserve revisions

 

 

(570,364

)

Proved undeveloped reserves, December 31, 2019

 

 

 

 

Conversions:     In 2019, the conversion rate was 19.8% based on PUD reserves recorded as of December 31, 2018.

Additions/Extensions:  At December 31, 2019, the Company did not book any PUD reserves. Accordingly, there were no additions to the PUD reserve category.

Purchases: In 2019, there were no purchases related to PUD reserves.

Revisions:    At December 31, 2019, the Company transferred approximately 570 Bcfe of PUD reserves to unproven categories. Due to management’s decision to suspend its operated drilling program during 2019, we concluded we lacked the required degree of certainty about our financial capability to fund a development program and the availability of capital that would be required to develop PUD reserves.

March 2020 Reserves:

Impairment of Oil and Gas Properties in the Quarter Ended March 31, 2020

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings.

In order to fulfill its obligation to evaluate the full cost ceiling evaluation and to calculate DD&A of its oil and gas properties, the Company is required to estimate its reserves on a quarterly basis.  The estimated proven oil and gas reserves considers the estimated future production based on the most current well information available including decline rate changes causing downward revisions and updated pricing in accordance with SEC requirements.  The reserves estimated as of March 31, 2020 were prepared by Netherland, Sewell & Associates, Inc. The comparable calculated average prices utilized in the preparation of the reserves as of March 31, 2020 were $2.07 per Mcf and $55.35 per Bbl.  These prices represent a decrease of 15% and <1% for natural gas and oil, respectively, as compared to the pricing utilized as of December 31, 2019.

The reserve estimates as of March 31, 2020 are as follow:

 

 

Natural Gas

(MMcf)

 

 

Oil

(MBbls)

 

 

Natural Gas Equivalents (MMcfe)

 

Developed

 

 

1,694,828

 

 

 

11,902

 

 

 

1,766,239

 

Undeveloped

 

 

 

 

 

 

 

 

 

Total Proved as of March 31, 2020

 

 

1,694,828

 

 

 

11,902

 

 

 

1,766,239

 

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The future net cash flows, before income tax and the discounted future net cash flows before income tax estimated at March 31, 2020 were $1.907 billion and $1.218 billion, respectively.  As a result of the decrease in both quantities of oil and gas reserves, as well as the discounted future cash flow estimates, the Company estimates it will record an increased rate of DD&A per Mcfe and require a material impairment charge to its oil and gas properties due to the ceiling test limitation in the quarter ended March 31, 2020.

Internal Controls Over Reserve Estimating Process

Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserve quantities and present values in compliance with the SEC’s regulations and with GAAP. Our Director of Reservoir and Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates and has a Bachelor of Science degree in Petroleum Engineering with over 15 years of experience.

The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation as well as ultimate approval of our capital budget and review of our development plan by our senior management and Board of Directors. The development plan underlying the Company’s PUD reserves, if any, is further subject to internal controls, including a comparison of future development costs to historical expenditures as well as our future development plan and financial capabilities, and an evaluation of the estimated profitability of each location at the time the report is prepared. The development plan underlying the Company’s PUD reserves, adopted every year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data, and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals, and substitutions of previously scheduled PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders.

The estimates of proved reserves and future net revenue as of December 31, 2019 are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.

The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates for all of the Company’s assets for the period ended March 31, 2020 and the years ended December 31, 2019, 2018 and 2017, which are included in this annual report.

The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F 2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No. 125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over eight years of prior industry experience. He graduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 15 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines

Our internal professional staff works closely with NSAI to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. The NSAI reports are included as Exhibits 99.1 and 99.2 to this annual report.

 

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Production Volumes, Average Sales Prices and Average Production Costs

The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with the Company’s sale of oil and natural gas for the periods indicated.

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands, except per unit data)

 

Production

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

 

230,121

 

 

 

260,406

 

 

 

260,009

 

Oil (Bbl)

 

 

1,683

 

 

 

2,442

 

 

 

2,775

 

Total (Mcfe)

 

 

240,219

 

 

 

275,058

 

 

 

276,659

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

637,007

 

 

$

722,313

 

 

$

748,682

 

Oil sales

 

 

97,231

 

 

 

153,534

 

 

 

133,368

 

Other revenues

 

 

7,794

 

 

 

16,652

 

 

 

9,823

 

Total revenues

 

$

742,032

 

 

$

892,499

 

 

$

891,873

 

Lease Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (1)

 

$

70,608

 

 

$

90,290

 

 

$

92,326

 

Facility lease expense

 

 

25,468

 

 

 

25,947

 

 

 

21,749

 

Production taxes

 

 

79,459

 

 

 

93,322

 

 

 

91,067

 

Gathering

 

 

78,261

 

 

 

89,294

 

 

 

87,287

 

Transportation charges

 

 

1,496

 

 

 

512

 

 

 

(334

)

Total lease operating expenses

 

$

255,292

 

 

$

299,365

 

 

$

292,095

 

Average Realized Prices

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf, including realized gains (losses) on commodity derivatives)

 

$

2.50

 

 

$

2.48

 

 

$

2.92

 

Natural gas ($/Mcf, excluding realized gains (losses) on commodity derivatives)

 

$

2.77

 

 

$

2.77

 

 

$

2.88

 

Oil ($/Bbl, including realized gains (losses) on commodity derivatives)

 

$

59.97

 

 

$

59.44

 

 

$

48.05

 

Oil ($/Bbl, excluding realized gains (losses) on commodity derivatives)

 

$

57.78

 

 

$

62.88

 

 

$

48.05

 

Average Costs per Mcfe

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

0.29

 

 

$

0.33

 

 

$

0.33

 

Facility lease expense

 

 

0.11

 

 

 

0.09

 

 

 

0.08

 

Production taxes

 

 

0.33

 

 

 

0.34

 

 

 

0.33

 

Gathering

 

 

0.33

 

 

 

0.33

 

 

 

0.31

 

Transportation charges

 

 

0.01

 

 

 

-

 

 

 

-

 

DD&A

 

 

0.85

 

 

 

0.74

 

 

 

0.59

 

General & administrative

 

 

0.11

 

 

 

0.09

 

 

 

0.14

 

Interest

 

 

0.54

 

 

 

0.54

 

 

 

1.31

 

Total costs per Mcfe

 

$

2.57

 

 

$

2.46

 

 

$

3.09

 

 

(1)Lease operating costs include lifting costs and remedial workover expenses.

 

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The following table sets forth the net sales volumes, operating expenses and average realized natural gas prices attributable to the Pinedale field, which is the only field that contained 15% or more of our total estimated proved reserves for each year:

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Pinedale Field:

 

 

 

 

 

 

 

 

 

 

 

 

Production (Mcfe)

 

 

237,851

 

 

 

264,786

 

 

 

256,695

 

Operating expenses

 

$

252,165

 

 

$

282,376

 

 

$

265,051

 

Average realized price ($/Mcf excluding realized gains (losses) on commodity derivatives)

 

$

2.77

 

 

$

2.78

 

 

$

2.90

 

Average realized price ($/Mcf including realized gains (losses) on commodity derivatives)

 

$

2.49

 

 

$

2.48

 

 

$

2.95

 

 

Delivery Commitments

With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Part I. Item 1A. “Risk Factors.” If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments.

Productive Wells

As of December 31, 2019, the Company’s total gross and net wells were as follows:

 

 

 

Gross Wells

 

 

Net Wells

 

Productive Wells*

 

 

 

 

 

 

 

 

Operated

 

 

2,265

 

 

 

1,943

 

Operated by others

 

 

854

 

 

 

241

 

Total productive wells

 

 

3,119

 

 

 

2,183

 

 

*

Productive wells are producing wells, shut-in wells the Company deems capable of production, wells that are waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests the company owns in gross wells.

Oil and Gas Acreage

The primary terms of the Company’s oil and gas leases expire at various dates. Much of the Company’s undeveloped acreage is held by production, which means that the Company will maintain its rights in these leases as long as oil or natural gas is produced from the acreage by it or by other parties holding interests in producing wells on those leases. In some cases, if production from a lease ceases, the lease will expire, and in some cases, if production from a lease ceases, the Company may maintain the lease by additional operations on the acreage.

The Company does not believe the risk of remaining terms of its leases are material. The Company expects to maintain essentially all the material leases among its oil and gas properties by production, operations, extensions or renewals. The Company does not expect to lose material lease acreage because of failure to drill due to inadequate capital, equipment or personnel. The Company has, based on its evaluation of prospective economics, allowed acreage to expire and it may allow additional acreage to expire in the future. As of December 31, 2019, the Company estimates that approximately 6,300 net leased acres may expire in 2020 through 2022, and approximately 7,200 net leased acres in Wyoming may expire in 2023 through 2029.

As of December 31, 2019, the Company had total gross and net developed and undeveloped oil and natural gas leasehold acres in the United States as set forth below.

 

 

 

Developed Acres

 

 

Undeveloped Acres

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Wyoming

 

 

45,000

 

 

 

30,000

 

 

 

72,000

 

 

 

53,000

 

 

35


Table of Contents

 

Drilling Activities

The number of gross and net wells drilled by the Company during each of the three fiscal years ended December 31, 2019, 2018 and 2017 are reflected in the tables below. The well counts in these tables represent classification and costs specific to the reserves deemed to be proved or unproved. Such wells may be completed and turned into sales during different period.

Wyoming — Green River Basin

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

64.0

 

 

 

51.0

 

 

 

107.0

 

 

 

80.7

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

64.0

 

 

 

51.0

 

 

 

107.0

 

 

 

80.7

 

 

 

 

 

 

 

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Exploratory Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

20.0

 

 

 

20.0

 

 

 

28.0

 

 

 

19.8

 

 

 

210.0

 

 

 

172.1

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

20.0

 

 

 

20.0

 

 

 

28.0

 

 

 

19.8

 

 

 

210.0

 

 

 

172.1

 

 

At December 31, 2019, there were 9.0 gross (3.8 net) exploratory wells which were suspended at a depth short of total depth and thus a determination of productive capability could not be made at year-end.

Utah

The Company divested its Utah assets during the third quarter of 2018. For the years ended December 31, 2018 and 2017, the Company did not drill any development or exploratory wells on its Utah acreage.

Pennsylvania

The Company divested its Pennsylvania assets during the fourth quarter of 2017.  For the years ended December 31, 2017, the Company did not drill any development or exploratory wells on its Pennsylvania acreage.    

Colorado

The Company did not conduct any operations on this acreage during 2019, 2018 or 2017. In 2014, the Company sold the surface rights to its Colorado undeveloped acreage and retained some oil and gas mineral rights. The Company no longer owns any leased acreage in Colorado and has no immediate plans for further exploration in Colorado during 2020.

Item 3.

Legal Proceedings.

See Note 14 for discussion of on-going claims and disputes that arose during our chapter 11 proceedings, certain of which may be material. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

Item 4.

Mine Safety Disclosures.

None.

 

36


Table of Contents

 

PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s common shares are traded on the OTCQX marketplace under the symbol “UPLC”.  As of March 31, 2020, there were approximately 313 holders of record of the common shares.

Dividends

 

The Company has not declared or paid and does not anticipate declaring or paying any dividends on its common shares in the near future.  Additionally, our Credit Agreement, Term Loan Agreement, and the Second Lien Indenture (as defined below) place certain restrictions on our ability to pay cash dividends. The Company intends to retain its cash flow from operations for the future operation and development of its oil and gas properties.

Unregistered Sales of Equity Securities

 

Purchases of Equity Securities by Issuer

The following table provides information about purchases made by the Company (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the twelve months ended December 31, 2019, of shares of common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act:

 

Period

 

Total Number of Shares Purchased (1)

 

 

Weighted Average Price Paid per Share

 

 

Total Number of Shares Purchased as Part of Publicly Announced Program

 

Maximum Number of Shares that May Yet Be Purchased Under the Program

January 2019