Company Quick10K Filing
Atlas Growth Partners
Price-0.00 EPS-0
Shares23 P/E0
MCap-0 P/FCF0
Net Debt-3 EBIT-3
TEV-3 TEV/EBIT1
TTM 2019-09-30, in MM, except price, ratios
10-K 2019-12-31 Filed 2020-04-16
10-Q 2019-09-30 Filed 2019-11-14
10-Q 2019-06-30 Filed 2019-08-14
10-Q 2019-03-31 Filed 2019-05-20
10-K 2018-12-31 Filed 2019-04-16
10-Q 2018-09-30 Filed 2018-11-19
10-Q 2018-06-30 Filed 2018-08-17
10-Q 2018-03-31 Filed 2018-06-11
10-K 2017-12-31 Filed 2018-05-08
10-Q 2017-09-30 Filed 2017-11-14
10-Q 2017-06-30 Filed 2017-08-14
10-Q 2017-03-31 Filed 2017-05-15
10-K 2016-12-31 Filed 2017-04-17
10-Q 2016-09-30 Filed 2016-11-07
10-Q 2016-06-30 Filed 2016-08-08
10-Q 2016-03-31 Filed 2016-05-16
8-K 2020-06-19
8-K 2020-05-15
8-K 2020-05-01
8-K 2020-04-14
8-K 2019-06-05
8-K 2019-05-01
8-K 2018-10-31
8-K 2018-07-26
8-K 2018-03-27
8-K 2018-03-05

AGP 10K Annual Report

Part I
Item 1: Business
Item 1A: Risk Factors
Item 1B: Unresolved Staff Comments
Item 2: Properties
Item 3: Legal Proceedings
Item 4: Mine Safety Disclosures
Part II
Item 5: Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 6: Selected Financial Data
Item 7: Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A: Quantitative and Qualitative Disclosures About Market Risk
Item 8: Financial Statements and Supplementary Data
Note 1 - Basis of Presentation
Note 2 - Summary of Significant Accounting Policies
Note 3 - Property, Plant and Equipment
Note 4 - Derivative Instruments
Note 5 - Asset Retirement Obligations
Note 6 - Fair Value of Financial Instruments
Note 7 - Certain Relationships and Related Party Transactions
Note 8 - Commitments and Contingencies
Note 9 - Issuances of Units
Note 10 - Cash Distributions
Note 11 - Correction of An Immaterial Error
Note 12 - Supplemental Oil and Gas Information (Unaudited)
Note 13 - Quarterly Results (Unaudited)
Note 14 - Subsequent Event
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A: Controls and Procedures
Item 9B: Other Information
Part III
Item 10: Directors, Executive Officers and Corporate Governance
Item 11: Executive Compensation Discussion and Analysis
Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13: Certain Relationships and Related Transactions, and Director Independence
Item 14: Principal Accountant Fees and Services
Part IV
Item 15: Exhibits, Financial Statement Schedules
EX-21.1 agp-ex211_7.htm
EX-23.1 agp-ex231_8.htm
EX-31.1 agp-ex311_6.htm
EX-31.2 agp-ex312_9.htm
EX-32.1 agp-ex321_10.htm
EX-32.2 agp-ex322_11.htm
EX-99.1 agp-ex991_12.htm

Atlas Growth Partners Earnings 2019-12-31

Balance SheetIncome StatementCash Flow
15012090603002015201620182020
Assets, Equity
3.5-7.2-17.9-28.6-39.3-50.02015201620182020
Rev, G Profit, Net Income
151050-5-102015201620182020
Ops, Inv, Fin

10-K 1 agp-10k_20191231.htm 10-K agp-10k_20191231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2019

OR

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: 000-55603

 

Atlas Growth Partners, L.P.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

80-0906030

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

425 Houston Street, Suite 300

Fort Worth, TX

 

76102

(Address of principal executive offices)

 

(Zip code)

 

Registrant’s telephone number, including area code: 412-489-0006

 

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

None

N/A

N/A

 

Securities registered pursuant to Section 12(g) of the Act:

Common units representing limited partner interests; warrants to purchase common units at an exercise price of $10.00 per common unit

(Title of class)

 

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 15(d) of the Exchange 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 (§232.405 of this chapter) 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, a 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 Exchange Act).     Yes       No  

As of June 30, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s commons units were not publicly traded. Accordingly, there was no market value for the registrant’s common units on such date.

The number of outstanding common limited partner units of the registrant on April 16, 2020 was 23,300,410.

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 


 

ATLAS GROWTH PARTNERS, L.P.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

 

 

 

  

 

Page

PART I

 

Item 1:

  

Business

7

 

 

Item 1A:

  

Risk Factors

19

 

 

Item 1B:

  

Unresolved Staff Comments

41

 

 

Item 2:

  

Properties

41

 

 

Item 3:

  

Legal Proceedings

41

 

 

Item 4:

  

Mine Safety Disclosures

41

 

 

 

 

 

 

PART II

 

Item 5:

  

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

42

 

 

Item 6:

  

Selected Financial Data

43

 

 

Item 7:

  

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

44

 

 

Item 7A:

  

Quantitative and Qualitative Disclosures about Market Risk

50

 

 

Item 8:

  

Financial Statements and Supplementary Data

52

 

 

Item 9:

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

72

 

 

Item 9A:

  

Controls and Procedures

73

 

 

Item 9B:

  

Other Information

73

 

 

 

 

 

 

PART III

 

Item 10:

  

Directors, Executive Officers and Corporate Governance

74

 

 

Item 11:

  

Executive Compensation

78

 

 

Item 12:

  

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

81

 

 

Item 13:

  

Certain Relationships and Related Transactions, and Director Independence

82

 

 

Item 14:

  

Principal Accountant Fees and Services

83

 

 

 

 

 

 

PART IV

 

Item 15:

  

Exhibits and Financial Statement Schedules

84

 

 

 

 

 

 

SIGNATURES

86

 

 

2


 

GLOSSARY OF TERMS

Unless the context otherwise requires, references below to “Atlas Growth Partners, L.P.,” “Atlas Growth Partners,” “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Growth Partners, L.P. and our consolidated subsidiaries.

Bbl. One barrel of crude oil, condensate or other liquid hydrocarbons equal to 42 United States gallons.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl oil, condensate or natural gas liquids.

Bpd. Barrels per day.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

dry hole or well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exchange Act. The Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well (as such terms are defined in the federal securities laws).

FASB. Financial Accounting Standards Board.

field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms, structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

fractionation. The process used to separate a natural gas liquid stream into its individual components.

GAAP. Generally Accepted Accounting Principles in the United States of America.

gross acres or gross wells. A gross well or gross acre in which we own a working interest.

IDR. Incentive distribution rights.

MLP. Master limited partnership.

MBbl. One thousand barrels of crude oil, condensate or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.

Mcfe. Mcf of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

3


 

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

MMBbl. One million barrels of crude oil, condensate or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcfe. One million cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfed. One MMcfe per day.

net acres or net wells. A net well or net acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions of whole numbers.

natural gas liquids or NGLs —A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus (the main constituent of condensates).

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock Exchange.

oil. Crude oil and condensate.

Partnership Agreement. Our First Amended and Restated Limited Partnership Agreement.

productive well. A producing well or well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

proved developed reserves. Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

 

(a)

The area identified by drilling and limited by fluid contacts, if any, and

 

(b)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

4


 

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(a)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

(b)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. Present value of future net revenues. See the definition of “standardized measure.”

recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

SEC. Securities and Exchange Commission.

standardized measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Titan. Titan Energy, LLC, a publicly traded Delaware limited liability company (OTCQX: TTEN).

undeveloped acreage or undeveloped acres. Undeveloped acreage encompasses those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

working interest. An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.

5


 

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements.  These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology.  In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements.  We have based these forward-looking statements on our current expectations, assumptions, estimates and projections.  While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control.  These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.  Some of the key factors that could cause actual results to differ from our expectations include:

 

our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner;

 

the suspension of our quarterly distribution;

 

our lack of ability to raise capital, in the capital markets or otherwise;

 

our ability to continue as a going concern;

 

our business and investment strategy;

 

the effect of general market, oil and gas market (including volatility of realized price for oil, natural gas and natural gas liquids), and economic and political conditions;

 

uncertainties with respect to identified drilling locations and estimates of reserves;

 

our ability to generate sufficient cash flows to re-start distributions to our unitholders;

 

the degree and nature of our competition; and

 

the availability of qualified personnel at our general partner and Atlas Energy Group, LLC.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A: Risk Factors.  Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements.  The forward-looking statements included in this report are made only as of the date hereof.  We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

6


 

PART I

 

 

ITEM 1:

BUSINESS

General

We are a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC, owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and effectively controls us.

Atlas Energy Group, LLC (“ATLS”), a Delaware limited liability company, manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.

Management Overview and Outlook

Since our inception in 2013, we have developed into a company with a core position in the Eagle Ford Shale in south Texas generating stable cash flows, despite a significant decline in oil and natural gas prices.  While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses.  As of December 31, 2019, we had $2.2 million of cash on our balance sheet and no debt. Our general and administrative expenses increased $0.6 million to $4.5 million for the year ended December 31, 2019 from $3.9 million for the year ended December 31, 2018.

In 2018, we deployed $6.9 million of cash on hand to drill and complete one Eagle Ford Shale well, which turned in-line during the second quarter of 2018. The well has increased our production, and provided additional cash flow to our business. With this additional well, we have enhanced ability to generate positive cash flow from our operations, grow our cash balance, and take advantage of opportunities to drill new Eagle Ford Shale wells or take on other strategic initiatives and transactions should favorable conditions arise.

While we manage the company on a daily basis to optimize operating results, we also continue to explore ways to strategically grow and transform the company. Quarterly, we consider our ability to make distributions to unitholders; however, based on the company’s financial position and cash flows, we have not yet elected to resume making distributions following the suspension in November 2016. We continue to explore opportunities to drill additional wells across our Eagle Ford Shale locations.  Our ability to convert our locations into cash-flowing wells may be improved by raising additional capital, but we have limited avenues to do so at this time.  We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders.  We will continue to vigorously pursue all options to maximize returns to our investors.

Geographic and Geologic Overview

Through December 31, 2019, our production positions were in the following areas:

Eagle Ford. The Eagle Ford Shale is an Upper Cretaceous-age formation that is prospective for horizontal drilling in approximately 26 counties across south Texas. Target vertical depths range from 4,000 to some 11,000+ feet with thickness from 40 to over 400 feet. The Eagle Ford formation is considered to be the primary source rock for many conventional oil and gas fields including the prolific East Texas Oil Field, one of the largest oil fields in the contiguous United States. We acquired our Eagle Ford position through a series of acquisitions in 2014 and 2015 for approximately $100 million. We estimate 4 Bcfe of total proved reserves for our Eagle Ford position, of which 88% are oil. Over 99% of our production volumes and 98% of our revenues are derived from our Eagle Ford operations.

Marble Falls. The Marble Falls play is Pennsylvanian-age formation located above the Barnett Shale and beneath the Atoka at depths of approximately 5,500 feet and ranges in thickness from 50 and 500 feet. In January 2019, we sold our Marble Falls position, which resulted in a gain of $15 thousand after customary purchase price adjustments.

Mississippi Lime. The Mississippi Lime formation is an expansive carbonate hydrocarbon system and is located at depths between 4,000 and 7,000 feet between the Pennsylvanian-aged Morrow formation and the Devonian-age world-class source rock Woodford Shale formation. The Mississippi Lime formation can reach 600 feet in gross thickness, with a targeted porosity zone between 50 and 100 feet thickness. In July 2019, we sold our Mississippi Lime position, which resulted in a loss of $48 thousand after customary purchase price adjustments.

7


 

Gas and Oil Production

See Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations for a summary of our total net natural gas, oil and NGL production volumes, production per day, production revenue and average sales prices for our direct interest natural gas, oil and NGL production.

Natural Gas, Oil and NGL Reserves

The following tables summarize information regarding our estimated proved natural gas, oil and NGL reserves.  See Item 1A: Risk Factors—Risks Relating to Our Business and Item 8: Financial Statements and Supplementary Data—Note 12 for additional information and considerations regarding the preparation and estimates used in our reserves.

In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month prices for the preceding twelve months from the periods indicated, which are listed below along with our average realized prices over the same twelve month period.

 

 

 

December 31,

 

 

 

2019

 

2018

 

Unadjusted Prices

 

 

 

 

 

 

 

Natural gas (per MMBtu)

 

$

2.58

 

$

3.10

 

Oil (per Bbl)

 

$

55.69

 

$

65.56

 

Natural gas liquids (per Bbl)

 

$

15.59

 

$

25.57

 

Average Realized Prices, Unhedged

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

1.21

 

$

2.03

 

Oil (per Bbl)

 

$

57.99

 

$

67.13

 

Natural gas liquids (per Bbl)

 

$

13.50

 

$

24.26

 

 

 

 

 

December 31,

 

 

 

2019

 

2018

 

Proved reserves:

 

 

 

 

 

 

 

Natural gas reserves (MMcf):

 

 

 

 

 

 

 

Proved developed reserves

 

 

283

 

 

292

 

Proved undeveloped reserves

 

 

 

 

810

 

Total proved reserves of natural gas

 

 

283

 

 

1,102

 

Oil reserves (MBbl):

 

 

 

 

 

 

 

Proved developed reserves

 

 

493

 

 

676

 

Proved undeveloped reserves

 

 

 

 

3,191

 

Total proved reserves of oil

 

 

493

 

 

3,867

 

NGL reserves (MBbl):

 

 

 

 

 

 

 

Proved developed reserves

 

 

53

 

 

69

 

Proved undeveloped reserves

 

 

 

 

190

 

Total proved reserves of NGL

 

 

53

 

 

259

 

Total proved reserves (MMcfe)

 

 

3,558

 

 

25,857

 

Standardized measure of discounted future cash

flows (in thousands)

 

$

7,827

 

$

51,715

 

 

Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion.

8


 

Proved Undeveloped Reserves (“PUDs”)

PUD Locations. As of December 31, 2019, we had no PUD locations primarily due to the uncertainty of availability of capital for future development. These PUDs are based on the definition of PUDs in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

 

Material changes in PUDs. As of January 1, 2019, we had 12 PUD locations totaling approximately 21 net Bcfe’s of natural gas, oil, and NGLs.  Material changes in PUDs for the year ended December 31, 2019 resulted from the removal of proved undeveloped properties as a result of uncertainty regarding our ability to access capital to develop the proved undeveloped reserves.

Development Costs. There were no development costs incurred during the year ended December 31, 2019.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we had a working interest as of December 31, 2019. Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in which we have an interest directly and net wells are the sum of our fractional working interests in gross wells:

 

 

 

Number of productive

wells(1)

 

 

Gross

 

Net

Gas wells

 

 

Oil wells

 

11

 

11

Total

 

11

 

11

 

(1)

There were no exploratory wells drilled in any of our operating areas. There were no gross or net dry wells within any of our operating areas.

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2019:

 

 

 

Developed acreage (1)

 

Undeveloped acreage(2)

 

 

Gross (3)

 

Net (4)

 

Gross (3)

 

Net (4)

Texas

 

2,844

 

2,840

 

 

Total

 

2,844

 

2,840

 

 

 

(1)

Developed acres are acres spaced or assigned to productive wells.

(2)

Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)

A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(4)

Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have primary terms that vary from less than one year to two years with options to extend. There were no concessions for undeveloped acreage as of December 31, 2019. As of December 31, 2019, there were no leases set to expire on or before December 31, 2020 and 2021.

We believe that we hold good and indefeasible title related to our producing properties, in accordance with standards generally accepted in the industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

9


 

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Drilling Activities

Our drilling activities are conducted mostly on undeveloped acreage. There were no gross or net dry wells drilled during the periods presented below. The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the periods indicated:

 

 

 

Years Ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Gross wells drilled(1)

 

 

 

 

 

1

 

 

 

 

Net wells drilled(1)

 

 

 

 

 

1

 

 

 

 

Gross wells turned in line (2)

 

 

 

 

 

1

 

 

 

 

Net wells turned in line(2)

 

 

 

 

 

1

 

 

 

 

 

(1)

There were no exploratory wells drilled for each of the periods presented.

(2)

Wells turned in line refers to wells that have been drilled, completed and connected to a gathering system. The well turned in line was in our Eagle Ford position.

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We perform regular inspection, testing and monitoring functions on each of our operated wells.

In 2018, we deployed $6.9 million of cash on hand to drill and complete one Eagle Ford Shale well, which turned in-line during the second quarter of 2018.

Natural Gas and Oil Leases

The typical oil and gas lease agreement provides for the payment of a percentage of the proceeds, known as a royalty, to the mineral owner(s) for all natural gas, oil and other hydrocarbons produced from any well(s) drilled on the leased premises. In Texas (Eagle Ford Shale play), where we have acquired acreage positions, royalties are commonly in the 15-25% range, resulting in net revenue interests to us in the 75-85% range.

In the Texas Eagle Ford Shale play, where horizontal wells are generally drilled on much larger drilling units (sometimes approaching 1,000 acres), the mineral and/or surface rights are generally acquired from multiple parties.

Because the acquisition of hydrocarbon leases in highly desirable basins is an extremely competitive process, and involves certain geological and business risks to identify prospective areas, leases are frequently held by other oil and gas operators. In order to access the rights to drill on those leases held by others, we may elect to farm-in lease rights and/or purchase assignments of leases from competitor operators. Typically, the assignor of such leases will reserve an overriding royalty interest (over and above the existing mineral owner royalty), that can range from 2-3% up to as high as 7% or 8%, and sometimes contain options to convert the overriding royalty interests to working interests at payout of a well. Areas where farm-ins are utilized can result in additional reductions in our net revenue interests, depending upon their terms and how much of a particular drilling unit the farm-in acreage encompasses.

There will be occasions where competitors owning leasehold interests in areas where we want to drill will not farm-out or sell their leases, but will instead join us as working interest partners, paying their proportionate share of all drilling and operating costs in a well. However, it is generally our goal to obtain 100% of the working interest in any and all new wells that we operate.

10


 

Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. We market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The pricing for our Eagle Ford production is primarily Houston Ship Channel daily prices. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of natural gas in any future periods under existing contracts or agreements.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting on behalf of the oil purchaser. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our NGLs are generally priced and sold using the Mont Belvieu (TX) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2019, Shell Trading Co individually accounted for approximately 95% of our total natural gas, crude oil and NGLs production revenue with no other single customer accounting for more than 10% for this period, excluding the impact of all financial derivative activity.

Oil Hedging

We may seek to provide greater stability in our cash flows through the use of financial hedges for our oil production. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with our secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. As of December 31, 2019, we do not hold any derivative contract positions.

Natural Gas Gathering Agreements

Virtually all natural gas produced is gathered through one or more pipeline systems before sale or delivery to a purchaser or an interstate pipeline. A gathering fee can be charged for each gathering activity that is utilized and by each separate gatherer providing the service. Fees will vary depending on the distance the gas travels and whether additional services such as compression, blending, or treating are provided.

Availability of Energy Field Services

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. Over the past year, we and other oil and natural gas companies have experienced a significant reduction in drilling and operating costs. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the supply and demand for natural gas and oil.

11


 

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from independent oil and gas companies, MLPs and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging for the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or other resources will permit.

Competition is strong for attractive oil and natural gas properties and there can be no assurances that we will be able to compete satisfactorily when attempting to make acquisitions. In general, sellers of producing properties are influenced primarily by the price offered for the property, although a seller also may be influenced by the financial ability of the purchaser to satisfy post-closing indemnifications, plugging and abandoning operations and similar factors.

We also may be affected by competition for drilling rigs, human resources and the availability of related oilfield services and equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

 

Environmental, Health and Safety Matters and Regulation

Our oil and natural gas operations are subject to stringent and complex laws and regulations pertaining to drilling and production, health, safety and the environment. As operators within the complex natural gas and oil industry, we must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

 

restricting the way waste disposal is handled;

 

limiting or prohibiting drilling, construction and operating activities in sensitive areas such as wetlands, coastal regions, air quality non-attainment areas, tribal lands, or areas inhabited by threatened or endangered species;

 

requiring the acquisition of various permits before the commencement of drilling;

 

restricting the rate and method of production and operation of wells;

 

restricting the venting or flaring of natural gas;

 

imposing requirements on the plugging and abandoning of wells;

 

requiring the installation of expensive pollution control equipment and water treatment facilities;

 

restricting the types, quantities and concentration of various substances that can be released into the environment in connection with siting, drilling, completion, production, and plugging activities;

 

requiring remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

 

enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations;

 

imposing substantial liabilities for pollution resulting from operations; and

 

requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

12


 

While we believe that compliance with existing federal, state and local environmental laws and regulations has not had a material adverse effect on our operations, there can be no assurance that compliance with future federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot be sure that future events, such as changes in existing laws, the more stringent interpretation or enforcement of existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

Environmental laws and regulations that could have a material impact on our operations include the following:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA.” NEPA requires federal agencies, including the Department of the Interior, to evaluate major federal agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Hydraulic Fracturing.  In recent years, federal, state, and local scrutiny of hydraulic fracturing has increased.  Regulation of the practice remains largely the province of state governments. Under the Obama Administration, however, steps were taken towards some federal regulation of hydraulic fracturing. On March 26, 2015, the Bureau of Land Management (“BLM”) issued a final rule requiring disclosure of hydraulic fracturing chemicals, establishing effluent limitations produced water must meet before being discharged to a publicly owned treatment plant, and imposing conditions for hydraulic fracturing operations on federal and tribal lands. Moreover, in December 2016 the prior Administration released the final report of its study of the impacts of hydraulic fracturing on drinking water in the U.S., finding that the hydraulic fracturing water cycle can impact drinking water resources under some circumstances.  At the time, this study was expected to provide more impetus to federal regulation of the management of hydraulic fracturing fluids and wastewater. With the change of Administration, however, interest in federal regulation waned, and in September 2018, the BLM rescinded the final rule that had been issued under the prior Administration. Court challenges to the rescinding of the rule remain pending before the U.S. District Court for the Northern District of California, and there remains uncertainty regarding the final outcome of this litigation. While we do not currently expect new federal regulations to be adopted, if they were, they could increase our cost to operate.

Although hydraulic fracturing is not currently the subject of substantial environmental regulation at the federal level, a number of states, and local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements. Common elements of state regulations governing hydraulic fracturing may include, but not be limited to, the following: requirement that logs and pressure test results are included in disclosures to state authorities; disclosure of hydraulic fracturing fluids and chemicals, potentially subject to trade secret/confidential proprietary information protections, and the ratios of same used in operations; specific disposal regimens for hydraulic fracturing fluids; replacement/remediation of contaminated water assets; minimum depth of hydraulic fracturing; and measures aimed at reducing or preventing induced seismicity, including putting certain areas off limits for hydraulic fracturing. Some states and localities have banned or are considering banning hydraulic fracturing altogether.

Oil Spills.  The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities, vessels and pipelines to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe that compliance with OPA has not had a material adverse effect on our operations, future inadvertent noncompliance, including accidental spills or releases, could result in varying civil and criminal penalties and liabilities.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations impose a number of different types of requirements on our operations.  First, these laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Second, the Clean Water Act prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers.  The precise definition of waters and wetland subject to the dredge-and-fill permit requirement has been enormously complicated and is subject to recurrent litigation and rulemaking.  A broader definition could result in more water and wetlands being subject to protection creating the possibility of additional permitting requirements for some of our existing or future facilities.  Third, the Clean Water Act requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills.   Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. While we believe that compliance with the Clean Water Act has not had a material adverse effect on our operations, future inadvertent noncompliance could result in varying civil and criminal penalties and liabilities.

13


 

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected.  Clean Air Act rules impose additional emissions control requirements and practices on some of our operations. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new or revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.

States are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations. States in which air emissions from oil and natural gas operations, including well sites, compressor stations, and pipelines are a substantial contributor to air pollution have adopted comprehensive air emissions permitting regimes.  

While we believe that compliance with the existing requirements of the Clean Air Act and comparable state laws and regulations has not had a material adverse effect on our operations, we will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air emissions.  We do not expect future requirements to be any more burdensome to us than other similarly situated companies.

Greenhouse Gas Regulation and Climate Change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business.  During and before the prior Administration, several Clean Air Act regulations were adopted to reduce greenhouse gas emissions, and a couple foundational findings were upheld by the courts.  In April 2007, the Supreme Court held in Massachusetts v. EPA that greenhouse gases are “air pollutants” covered by the Clean Air Act.  In December 2009, the EPA issued a final determination that greenhouse gases “endanger” public health and welfare, which was upheld in court in Coalition for Responsible Regulation, Inc. v. EPA.  In light of these findings and rulings, the EPA attempted to require the permitting of greenhouse gas emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control greenhouse gas emissions when a permit is required due to emissions of other pollutants. The EPA has adopted a mandatory greenhouse gas emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities. On March 28, 2017, President Trump issued an Executive Order on Promoting Energy Independence and Economic Growth explaining how his Administration would withdraw, rescind, revisit, or revise virtually every element of the Obama Administration’s program for reducing greenhouse gas emissions. Under the Executive Order, some actions had immediate effect.  Other actions, including those most directly affecting our operations and the overall consumption of fossil fuels, will be the subject of potentially lengthy notice-and-comment rule-making.  With respect to rules more directly applicable to the types of operations we conduct, federal agencies have begun the rule-making as directed by the Executive Order.  Initial efforts to revise or rescind 2015 methane emissions standards for new or modified wells were invalidated by the courts but corrective rule-making initiated, with the EPA proposing additional amendments to the rule in the fall of 2018.  With respect to rules of greater applicability affecting overall consumption of fossil fuels, federal agencies have also initiated rule-making to give effect to the Executive Order.  The most sweeping action was the replacement of the 2015 Clean Power Plan – the rule aimed at reducing greenhouse gas emissions from existing power plants by one-third (compared to 2005 levels).  In August 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule to replace the Clean Power Plan, which was finalized on June 19, 2019.

While we generally foresee a less stringent approach to the regulation of greenhouse gases, efforts at undoing the prior Administration’s greenhouse gas emissions regulations necessarily involve lengthy notice-and-comment rulemaking, and the resulting decisions may then be subject to litigation by those opposed to rescinding the prior Administration’s regulations.  It could be several years before the precise regulatory framework is known.  Opponents of the rescissions, including states and environmental groups, may then decide to sue large sources of greenhouse gas emissions for the alleged nuisance created by such emissions.  In 2011, the Supreme Court held that federal common law nuisance claims were displaced by the EPA’s authority to regulate greenhouse gas emissions from large sources of emissions. If the Administration fails to pursue regulation of emissions from such sources or takes the position that it has no authority to regulate their emissions, then it is possible that a court would find common law nuisance claims are no longer displaced.  In light of EPA’s ACE rule, the revival of public nuisance litigation may be less likely.

Although further regulation of greenhouse gas emissions from our operations may stall at the federal level, it is possible that, in the absence of federal regulation, states may pursue additional regulation of our operations, including restrictions on new and existing wells and fracturing operations, as many states already have done.

14


 

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. With authority granted by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. Following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016, the EPA and environmental groups entered into an agreement that required the EPA to either propose revisions to RCRA’s regulations governing oil and gas wastes, including the regulations that defined such wastes as “solid wastes” and not “hazardous wastes,” or to determine that such revisions were unnecessary. The EPA determined in 2019 that such revisions were unnecessary. Nonetheless, there is no guarantee that individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA’s or comparable states’ more stringent requirements.  While we believe that compliance with the requirements of RCRA and related state and local laws and regulations has not had a material adverse effect on our operations, future inadvertent noncompliance could result in varying civil and criminal penalties and liabilities. More stringent regulation of natural gas and oil exploration and production wastes could increase the costs to manage and dispose of such wastes.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” (but excluding petroleum) into the environment. These so-called potentially responsible parties (“PRP”) include the owner or operator of the site where the release occurred, regardless of whether a third party such as a prior owner or operator actually released the hazardous substances; former owners and operators of a site if the release occurred  during the period of their ownership or operation; and companies that disposed or arranged for the disposal of the hazardous substance at the site, notwithstanding that the original disposal activity may have accorded with applicable regulations. Under CERCLA, PRPs may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal.  Moreover, although CERCLA generally exempts “petroleum” from the definition of “hazardous substance,” in the course of our operations we generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. While we are not presently aware of the need for us to respond to releases of hazardous substances that would impose costs that would be material to our financial condition, there can be no assurance that no such incidents will occur in the future.

OSHA and Chemical Reporting Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes.  Portions of OSHA’s Respirable Crystalline Silica rule that apply to hydraulic fracturing became effective in June 2018, with additional engineering controls becoming effective in 2021.  While we believe we comply with the portions of the rule that became effective, we believe on-going compliance obligations could impose significant additional costs.  The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.  If the sectors to which community-right-to-know or similar chemical inventory reporting are expanded, our regulatory burden could increase.  While we believe that compliance with these applicable requirements and with other OSHA and comparable requirements has not had a material adverse effect on our operations, future inadvertent noncompliance could result in varying civil and criminal penalties and liabilities.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. We conduct our natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. We employ numerous safety precautions at our operations to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we believe we are in substantial compliance with all such requirements.

15


 

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing taxes and requirements for obtaining drilling permits.  States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced and an oil field clean-up fee of $.00625 per barrel of oil.

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 that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected properties that we own or lease. 

In August 2019, the Fish and Wildlife Service finalized revisions to ESA regulations that somewhat loosened procedures for listing species, recovery, reclassifications and critical habitat designations. The rules removed the requirement that listing, delisting or reclassification of species be made “without reference to possible economic or other impacts of such determination.” The rules also further relaxed the protection afforded to species listed as “threatened” from those that are endangered, with the protection for “threatened” species being made on more of a case-by-case basis.

Exports of US Oil Production and Natural Gas Production. In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales,” which include all of our sales of our own production.

Under the Energy Policy Act of 2005 (“EPAct”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.

16


 

FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions require compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. To date, FERC has declined to analyze potential upstream GHG emissions that could result from the activities of natural gas producers and marketers, like the Company, to be served by proposed interstate natural gas pipeline projects. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at the FERC and in the courts.

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.  The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain.

Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

17


 

The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate common carrier oil pipelines must provide service on a non-duly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various parties. Due to the pending rehearing of the order and its recency, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.

Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018.

Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act. The U.S. Commodities and Futures Exchange Commission (“CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affecting derivatives contracts that the Company uses to hedge its exposure to price volatility.

While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending, including a proposal to set position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents. The CFTC also has proposed, but not yet finalized, a rule regarding the capital posting requirements for swap dealers and major swap market participants. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to either rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

18


 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Employees

We do not directly employ any of the persons responsible for our management or operation which is performed by personnel employed by ATLS. As of December 31, 2019, approximately 35 ATLS employees provided direct management and support to our operations.

Available Information

We do not currently maintain a publicly-available website. However, you may receive, without charge, a paper copy of our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports by request to us at 425 Houston Street, Suite 300, Fort Worth, Texas 76102, telephone number (800) 251-0171. The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.  Copies of our filings can also be obtained on the SEC website at www.sec.gov.  

ITEM 1A:

RISK FACTORS

You should carefully consider each of the following risks, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this report. Some of the risks described below relate to our business, while others relate principally to the securities markets and ownership of our limited partnership interests. Partnership interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The risks and uncertainties we face are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. In addition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Related to an Investment in the Partnership

We may not have sufficient available cash to pay the full target distribution, or any distribution at all, on our common units and there is no guarantee that we will pay distributions to our unitholders in any quarter.

We may not have sufficient available cash each quarter to pay the full target distribution, or any distribution at all, to our unitholders. Furthermore, our Partnership Agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount of cash we have to distribute each quarter principally depends on the revenue we receive for our natural gas, oil and natural gas liquids. In addition, the actual amount of cash we will have available to distribute each quarter under the cash distribution policy that the board of directors of our general partner has adopted will be reduced by working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions that the board of directors may determine is appropriate. The board of directors of our general partner may change our cash distribution policy at any time without the approval of the unitholders or the conflicts committee of the board of directors of our general partner.

On November 2, 2016, the board of directors of our general partner determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain our cash flow and reinvest in our business and assets. At this time, we can provide no certainty as to when or if distributions will be reinstituted.

We rely exclusively on our general partner and ATLS to provide us with its facilities and personnel and to conduct operations.

We have no employees and no separate facilities. Consequently, we rely exclusively on our general partner and, because our general partner has no direct employees, ultimately upon ATLS, to provide its facilities and personnel and to conduct operations. Our general partner and, through it, ATLS, have significant discretion as to the implementation of our operating policies and investment strategies. Moreover, we believe that our success depends to a significant extent upon the experience of ATLS’s management team. The departure of any of the members of this management team could harm our investment performance.

19


 

There is no guarantee of return of investment or rate of return on investment because of the speculative nature of drilling natural gas and oil wells.

Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well, our general partner cannot predict with absolute certainty:

 

the volume of natural gas and oil recoverable from the well; or

 

the time it will take to recover the natural gas and oil.

You may not recover any or all of your investment in us or, if you do recover your investment in us, you may not receive a rate of return on your investment that is competitive with other types of investments that may be available to you. Except in the case of a liquidity event, you will be able to recover your investment only through distributions of our net proceeds from the sale of our natural gas and oil from productive wells. We anticipate that a liquidity event will occur within five years. However, there is no requirement that a liquidity event will occur within a specified timeframe or at all.

Our ability to convert our locations into cash flowing wells may be improved by raising additional capital.  We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders.  We will continue to vigorously pursue all options to maximize returns to our investors.

Our quarterly distributions may not be sourced from our cash generated from operations but from offering proceeds, and borrowings, among other sources, and this will decrease our cash available for distributions in the future.

There is no limitation on the amount of our distributions that can be funded from offering proceeds or financing proceeds. Our target distribution may be sourced from offering proceeds and borrowings, among other sources, rather than cash from operations. The payment of distributions from sources other than operating cash flow may decrease the cash available to invest in oil and gas properties, which may decrease our cash available for distributions in the future.

On November 2, 2016, our board of directors of our general partner determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain our cash flow and reinvest in our business and assets. At this time, we can provide no certainty as to when or if distributions will be reinstituted.

Distributions from us may be a return of capital rather than a return on your investment.

The amount of cash that we have available for distribution will depend on our cash flow, including cash reserves, working capital and borrowings, if any, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

If a listing event occurs, our Partnership Agreement will automatically be amended and restated, becoming the Post-Listing Partnership Agreement, which will alter some of your rights as a limited partner. 

If we undertake a listing event, our Partnership Agreement will automatically be amended and restated to become the Second Amended and Restated Agreement of Limited Partnership (the “Post-Listing Partnership Agreement”) and the common units will automatically convert into a new series of common units (the “Post-Listing common units”). Some of your rights as a limited partner will be altered as a result of that amendment and restatement, particularly voting rights. There is no requirement that a listing event will occur within a specified timeframe or at all.

Compensation and fees to our general partner will reduce cash distributions.

Our general partner has received its general partner interest and its IDRs for only nominal consideration. In addition, our general partner receives an annual management fee equal to 1.00% of total capital contributions to us (other than those of our general partner and its affiliates), payable quarterly, as well as reimbursement of direct costs regardless of the success of our wells. The amount of reimbursements paid to our general partner are subject to only narrow limits in certain circumstances such as the reimbursement of administrative costs to our general partner are limited to those supportable as to the necessity of such reimbursement and the reasonableness of the amount charged and supported by appropriate invoices or other documentation and other considerations. Otherwise, our Partnership Agreement and the other agreements we have with our general partner do not place meaningful limits on the magnitude of potential reimbursements; specifically, our general partner will determine which costs incurred are reimbursable and there are no limits on the amount of reimbursements on administrative costs to be paid to our general partner. These fees and reimbursements will reduce the amount of cash otherwise available for distribution to our limited partners.

20


 

On November 2, 2016, our management decided to suspend our primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues.  

The intended quarterly distributions may be reduced or delayed.

Cash distributions may not be paid each quarter. Distributions may be reduced or deferred, in the discretion of our general partner, due to local, state and federal regulations regarding permitting, fracturing, production, conservation, water disposal and treatment and pipeline construction and transportation of natural gas and oil, or to the extent our revenues are used for any of the following:

 

repayment of borrowings, if any;

 

any cost overruns in drilling and completing wells;

 

remedial work to improve a wells producing capability, including multiple hydraulic fracturing operations in each horizontal well;

 

our direct costs and general and administrative expenses;

 

reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

 

indemnification of our general partner and its affiliates by us for losses or liabilities incurred in connection with our activities.

Changes in laws or regulations that require an amendment to our Partnership Agreement could limit the rights of our limited partners.

Our general partner may, without the consent of our limited partners, amend our Partnership Agreement to reflect any changes as a result of a change in law or regulation that causes any term or condition set forth in our Partnership Agreement to be no longer viable, as determined by our general partner in its sole discretion. Our general partner expects that any such changes will be made as narrowly as possible in order to effectuate the original intent of our Partnership Agreement. Nevertheless, any such change could limit our rights and obligations or those of our limited partners.

Our Post-Listing Partnership Agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Our Post-Listing Partnership Agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our Post-Listing Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partners directors and officers.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its board of directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence managements decisions regarding our business. Unitholders do not elect our general partner or the members of its board of directors on an annual or other continuing basis. The board of directors of our general partner is elected by its unitholders. Furthermore, the vote of the holders of at least a majority of all outstanding common units is required to remove our general partner.

21


 

We may issue an unlimited number of common units and other equity securities, including interests that are senior to the common units, without approval of our limited partners, which would dilute your ownership interests in us.

Our Partnership Agreement does not limit the number of common units or other equity securities that we may issue at any time without the approval of our limited partners. In addition, we may issue an unlimited amount of interests that are senior to your interests in right of distribution, liquidation and voting. The issuance by us of equity interests of equal or senior rank will have the following effects:

 

your proportionate ownership interest in us will decrease;

 

your voting rights may be subject to voting rights of the newly issued interests;

 

the amount of cash available for distribution on your interests may decrease; and

 

the ratio of taxable income to distributions may increase.

In addition, the payment of distributions on any additional interests may increase the risk that we will not be able to make distributions at prior levels or at all. To the extent new interests are senior to the interests offered hereby, their issuance will increase the uncertainty of the payment of distributions.

The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

The common units are generally not liquid because there is not a readily available market for the sale of common units, and one is not expected to develop. Furthermore, although our Partnership Agreement contains provisions designed to permit the listing of the common units on a national securities exchange, the common units are currently not listed on any exchange or over-the-counter market and we may not be able to effect such listing within the expected five-year time frame following the completion of our private placement offering in June 2015 or at all. Your inability to sell or transfer your common units increases the risk that you could lose some or all of your investment because, if we are unable to meet our performance goals, you may not have the ability to transfer your common units prior to our winding up and liquidation.

We may be unable to sell our properties or list the common units on a national securities exchange within our planned timeline or at all.

We continue to evaluate and work towards either selling our properties and distributing the proceeds of the sale, after payment of liabilities and expenses, to our partners, with the approval of our general partner, or listing the common units on a national securities exchange. The decision to sell our properties will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of our assets, the projected amount of our oil and gas reserves, general economic conditions and other factors that are out of our control. In addition, the ability to list our common units on a national securities exchange will depend on a number of factors, including the state of the U.S. securities markets, our ability to meet the listing requirements of national securities exchanges, securities laws and regulations and other factors. If we are unable to either sell our properties or list the common units on a national securities exchange in accordance with our current plans, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment. There is no requirement that a liquidity event occur within a specified timeframe or at all.

Declining 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, volatile prices of oil, natural gas and NGLs, declining business and consumer confidence, energy costs, geopolitical issues, inflation and the availability and cost of credit have contributed to increased economic uncertainty and may diminish expectations for the global economy. 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 further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids produced 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.

22


 

We are an “emerging growth company” under the federal securities laws and are subject to reduced public company reporting requirements.

We are an emerging growth company, as defined in the JOBS Act, and are eligible to take advantage of certain exemptions from, or reduced disclosure obligations relating to, various reporting requirements that are normally applicable to public companies.

We could remain an emerging growth company until the earliest of (i) December 31 following the fifth anniversary of the date of the first sale of our common units pursuant to an effective registration statement filed under the Securities Act of 1933, as amended; (ii) December 31 of the first fiscal year in which we have total annual gross revenue of $1.07 billion or more; (iii) December 31 of the fiscal year that we become a large accelerated filer as defined in Rule 12b-2 under the Exchange Act (which would occur if the market value of our common units held by non-affiliates exceeds $700 million, measured as of the last business day of our most recently completed second fiscal quarter, and we have been publicly reporting for at least 12 months); or (iv) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period. Under the JOBS Act, emerging growth companies are not required to (a) provide an auditors attestation report on managements assessment of the effectiveness of internal control over financial reporting, pursuant to Section 404 of the Sarbanes-Oxley Act, (b) comply with new audit rules adopted by the PCAOB, (c) provide certain disclosures relating to executive compensation generally required for larger public companies or (d) hold shareholder advisory votes on executive compensation.

 

Risks Related to Conflicts of Interest

 

Our Partnership Agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our unitholders have agreed to be bound by our Partnership Agreement, which contains provisions that reduce the fiduciary standards to which our general partner is held. For example, our Partnership Agreement permits our general partner to:

 

have business interests or activities that may conflict with us;

 

devote only so much of its time as is necessary to manage the affairs of us, as determined by our general partner in its sole discretion;

 

conduct business with us in a capacity other than as general partner or sponsor as described in our Partnership Agreement;

 

with respect to farmouts to our general partner and its affiliates or unaffiliated third parties, our general partner will be subject to the lesser standard of prudent operator;

 

manage multiple programs simultaneously; and

 

be indemnified and held harmless.

ATLS, our general partner and the oil and gas and other professionals assembled by our general partner, face competing demands relating to their time, and this may cause our operations and our unitholders’ investments to suffer.

We rely on our general partner for the day-to-day operation of our business and the selection of our oil and gas properties. Certain of the directors and officers of ATLS and our general partner are key executives of other publicly traded entities, including Titan, and in other programs sponsored by ATLS and its affiliates. As a result of their interests in other programs sponsored by our sponsor, their obligations to other investors and the fact that they engage in and they will continue to engage in other business activities, these individuals will continue to face conflicts of interest in allocating their time among us and other programs sponsored by ATLS, Titan and ATLS’s other affiliates and other business activities in which they are involved. In addition, ATLS, Titan and ATLS’s other affiliates operate in the same industry as us and thus remain subject to all of the same risks that our business faces. The NYSE suspended the trading of ATLS’s common units at the close of trading on March 18, 2016, and ATLS’s common units currently trade on the OCTQB. ATLS’s delisting from the NYSE could have a negative effect on ATLS and its affiliates’ ability to operate our business and could impact our securities, as well. As a result, the returns on our investments, and the value of our unitholders’ investments, may decline.

23


 

The fiduciary duties of our general partner’s officers and directors may conflict with those they may have to affiliates of our general partner.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including ATLS and its affiliates), on the one hand, and our limited partners and us, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our unitholders. The directors and officers of ATLS have duties to manage ATLS and our general partner in a manner beneficial to its owners. In addition, many of the officers and directors of our general partner serve in similar capacities with ATLS and its affiliates, which may lead to additional conflicts of interest. At the same time, our general partner has certain fiduciary or contractual duties to us and our limited partners under our Partnership Agreement, the Post-Listing Partnership Agreement and applicable law.

Conflicts of interest between our general partner and our limited partners may not necessarily be resolved in favor of our limited partners.

There are potential conflicts of interest between our limited partners and our general partner and its affiliates. These conflicts of interest include the following:

 

our general partner has determined the compensation and reimbursement that it and its affiliates will receive in connection with us without arm’s-length negotiations;

 

we may be in competition with other oil and natural gas partnerships that have been and may be formed by our general partner and its affiliates in the future, including competition for properties to be acquired;

 

we may compete for management’s time and attention with other entities that our general partner and its affiliates may sponsor and/or manage in the future;

 

we may acquire projects from our general partner and its affiliates, and it is possible that those projects could constitute a substantial portion of our total projects;

 

on behalf of us, our general partner must monitor and enforce its own compliance with our Partnership Agreement and any activities conducted for us by officers, directors or employees of ATLS or its affiliates, all of whom are affiliates of our general partner;

 

our general partner will determine the amount and timing of cash distributions from us and the amount of cash reserved by us for future operations;

 

if our general partner, as partnership representative, represents us before the IRS there could be a potential conflict between our general partner’s determination of what is in the best interest of our limited partners as a group and the interests of a particular limited partner, including decisions as to whether to expend our funds to contest a proposed adjustment by the IRS, if any; and

 

the same legal counsel represents our general partner and us.

These conflicts of interest may not be resolved in a way satisfactory to some or all of our limited partners.

We may choose not to retain separate counsel or other service providers for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other hand, depending on the nature of the conflict, although we may choose not to do so.

24


 

Risks Related to Our Oil and Gas Operations

Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

 

the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas and oil on the domestic and global natural gas and oil supply;

 

the overall global level of industrial and consumer product demand;

 

the overall North American oil, natural gas and NGLs supply and demand fundamentals, including the U.S. economy, weather conditions and liquefied natural gas deliveries to and exports from the United States;

 

fluctuating seasonal demand;

 

political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;

 

the extent to which members of the Organization of Petroleum Exporting Countries and other exporting nations are able to influence global oil supply levels;

 

political and economic events that directly or indirectly impact the relative strength or weakness of the U.S. dollar, on which oil prices are benchmarked globally, against foreign currencies;

 

the price level of foreign imports;

 

the actions of governmental authorities;

 

the cost and availability of products and personnel needed for us to produce oil and natural gas, including rigs, crews, sand, water and water disposal;

 

the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;

 

inventory storage levels;

 

the nature and extent of domestic and foreign governmental regulations and taxation, including limits on the United States’ ability to export crude oil, environmental and climate change regulation;

 

the price, availability and acceptance of alternative fuels;

 

technological advances affecting energy consumption;

 

the quality of the oil we produce;

 

speculation by investors in oil and natural gas; and

 

variations between product prices at sales points and applicable index prices.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil.  In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue.  During the year ended December 31, 2019, the NYMEX Henry Hub natural gas index price ranged from a high of $3.59 per MMBtu to a low of $2.07 per MMBtu, and West Texas Intermediate (“WTI”) oil prices ranged from a high of $66.30 per bbl to a low of $46.54 per bbl.  

25


 

Any prolonged substantial decline in the price of oil and natural gas such as that experienced from 2015 until 2017 will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil and natural gas sales to reduce the impact of commodity price fluctuations.  However, the entire exposure of our operations from commodity price volatility is not currently hedged, and we may not be able to hedge such exposure going forward. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be further diminished.

In addition, low oil and natural gas prices can reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.  Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties.  In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices.

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 in several countries, including the United States, of a highly transmissible and pathogenic coronavirus (“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. 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 the Organization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

The Organization of Petroleum Exporting Countries (“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.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire natural gas and oil properties and to obtain capital, contract for drilling equipment and secure trained personnel.

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital, contracting for drilling equipment and securing trained personnel. Our competitors may be able to pay more for natural gas, natural gas liquids and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we do. Any of these factors could make it more difficult for us to execute our business strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective revenues or in raising additional capital.

26


 

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy, such as wind or solar power. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many oil and gas companies possess greater financial and other resources than we do, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we can.

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill wells and conduct our operations. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

Previous drilling by others may reduce our ability to find economically recoverable quantities of natural gas or oil.

Our primary drilling areas are located in areas where other oil and gas companies have previously drilled wells. As a result, many of the areas to be drilled by us are in locations that have already been partially depleted or drained by earlier drilling. This may reduce our ability to find economically recoverable quantities of natural gas and oil in those areas.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or 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 or suppliers 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.

We depend on certain key customers for sales of our natural gas, crude oil and NGLs. To the extent these customers reduce the volumes of natural gas, crude oil and NGLs they purchase or process from us, or cease to purchase or process natural gas, crude oil and NGLs from us, our revenues and cash available for distribution could decline.

We sell natural gas, crude oil and NGLs under contracts to purchasers in the normal course of business. For the year ended December 31, 2019, Shell Trading Co individually accounted for approximately 95% of our total natural gas, crude oil and NGLs production revenue, excluding the impact of all financial derivative activity. If one or more of our customers ceased purchasing our natural gas, crude oil and NGLs altogether, the loss of such customer could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes, which could in turn reduce our revenue and cash available for distribution.

An increase in the differential between the NYMEX or other benchmark prices of natural gas and oil and the wellhead price that we receive for our production could significantly reduce our cash available for distribution and limit our ability to maintain or expand our operations.

The prices that we receive for our natural gas and oil production sometimes reflect a discount to relevant benchmark prices, such as those on the New York Mercantile Exchange, or NYMEX. The difference between the benchmark price and the price that we receive is called a differential. Increases in the differential between the benchmark prices for natural gas and oil and the wellhead price that we receive could significantly reduce our cash available for distribution and limit our ability to maintain or expand our operations.

27


 

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only because dry holes may be drilled, but also because productive wells may not produce sufficient revenues to be commercially viable. This risk is exacerbated by the current decline in oil and gas prices. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

prolonged declines in oil, natural gas and NGLs prices;

 

higher costs, shortages or delivery delays of equipment and services;

 

unexpected operational events and drilling conditions;

 

adverse weather conditions;

 

facility or equipment malfunctions;

 

loss of title or other title-related issues;

 

pipeline ruptures or spills;

 

delays imposed by or resulting from compliance with environmental and other governmental requirements;

 

failure to obtain regulatory and third-party approvals;

 

actions by third-party operators of our properties;

 

unusual or unexpected geological formations;

 

formations with abnormal pressure;

 

injury or loss of life and property damage to a well or third-party property;

 

leaks or discharges of toxic gases, brine, natural gas, oil, hydraulic fracturing fluid and wastewater from a well;

 

environmental accidents, including groundwater contamination;

 

fires, blowouts, craterings and explosions; and

 

uncontrollable flows of natural gas or oil well fluids.

Any one or more of these factors could reduce or delay our receipt of drilling and production revenues and increase our costs, thereby reducing our ability to make distributions to our limited partners. In addition, any of these events can cause substantial losses, which may not fully be covered by insurance, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties, which could reduce our cash flow and our ability to make distributions to our limited partners.

Although we maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks are not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

Our operations require substantial capital expenditures to increase our asset base.  If we are unable to obtain needed capital or financing on satisfactory terms, our asset base will decline, which could cause our revenues to decline.

The natural gas and oil industry is capital intensive.  If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities.  This could cause our revenues to decline and diminish our ability to service any debt that we may have at such time.  If we do not make sufficient or effective capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations.

28


 

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would reduce our cash flows from operations and income.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas and oil reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and sources of capital, all of which are subject to the risks discussed elsewhere in this section. The value of our common units and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production or replace our declining production with new production. We may not be able to develop, exploit, find or acquire sufficient additional reserves or replace our current and future production.

A decrease in commodity prices could subject our oil and gas properties to impairment losses under U.S. generally accepted accounting principles.

 

U.S. generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We and our general partner will test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and estimated abandonment costs is less than the estimated expected undiscounted future cash flows. Expected future cash flows are estimated based on our or our general partner’s own economic interests and our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We and our general partner estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Natural gas and oil prices remain volatile and have recently declined substantially and could continue to decrease in the future. Prolonged depressed prices of natural gas or oil may cause the carrying value of our or our general partner’s oil and gas properties to exceed the expected future cash flows, and require that an impairment loss be recognized.  

Estimates of reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our estimates of our proved reserves are prepared by our internal engineers. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our standardized measure is calculated using natural gas prices that do not include financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from the reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of the estimated natural gas and oil reserves. We base the estimated discounted future net cash flows from proved reserves on historical prices and costs, but actual future net cash flows from our natural gas and oil properties will also be affected by factors such as:

 

actual prices received for natural gas and oil;

 

the amount and timing of actual production;

 

the amount and timing of capital expenditures;

 

supply of and demand for natural gas and oil; and

 

change in governmental regulations or taxation.

29


 

The timing of both the production and incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10.00% discount factor that we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the company or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of standardized measure, and the financial condition and results of operations. In addition, our reserves or standardized measure may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production could reduce the estimated volumes of reserves because the economic life of the wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our standardized measure.

Hedging transactions may limit our potential gains or cause us to lose money.

Pricing for natural gas, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we may use financial hedges and physical hedges for our production. Physical hedges are not deemed hedges for accounting purposes, but rather forward contracts because they require firm delivery of natural gas and oil and are considered normal sales of natural gas and oil.

In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The futures contracts are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

 

a counterparty is unable to satisfy its obligations;

 

production is less than expected; or

 

there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions and non-cash losses in our statement of operations.

We account for our derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in us recognizing a non-cash loss in our statements of operations and a consequent non-cash decrease in our equity between reporting periods. Any such decrease could be substantial. In addition, we may be required to make cash payments upon the termination of any of these derivative contracts.

30


 

Regulations adopted by the Commodities Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The ongoing implementation of derivatives legislation adopted by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The Dodd-Frank Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission (the “CFTC”), and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized many of the regulations associated with the reform legislation, and is in the process of implementing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits, subject to reporting and record keeping requirements and internal authorizations. The CFTC adopted final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants and financial end users (though non-financial end users are excluded from margin requirements).  While, as a non-financial end user, we are not subject to margin requirements, application of these requirements to our counterparties could affect the cost and availability of swaps we use for hedging. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation or regulations, our results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and/or cash flows.

We may not be able to identify suitable oil and gas properties.

Our investment strategy depends on our ability to acquire projects. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including difficulty in assessing recoverable reserves, future production rates, operating costs, infrastructure requirements, environmental and other liabilities, and other factors beyond our control. As a result, we may not recover our investment in a project from the sale of production from the project, or may not recognize an acceptable return from investments we make. A downturn in the credit markets and a potential lack of available debt could result in a further reduction of suitable investment opportunities and create a competitive advantage to other entities that have greater financial resources than we do. During such times, our ability to borrow monies to finance the purchase of, or other activities related to, oil and gas assets will be negatively impacted. In addition, if we pay fees to lock in a favorable interest rate, falling interest rates or other factors could require us to forfeit these fees. If we acquire properties and other investments at higher prices or by using less-than-ideal capital structures, our returns will be lower and the value of our assets may decrease significantly below the amount we paid for the assets.

We can give no assurance that we will be successful in identifying or, even if identified, acquiring suitable properties on financially attractive terms or that our objectives will be achieved. Any of these factors could adversely affect our ability to achieve our anticipated levels of cash flow from our projects, pay distributions and meet our investment objectives.  

Acquired properties may prove to be worth less than we paid, or provide less than anticipated proved reserves or production, because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our estimates of future reserves and estimates of future production for our acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by our or our general partner’s internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain; our proved reserves estimates may thus exceed actual acquired proved reserves. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not inspect every well. Even when we do inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and natural gas properties may exceed the value we realize.

31


 

Also, our reviews of the properties included in the acquisitions are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

Acquired properties may not produce as projected and we may be unable to determine reserve potential, identify all liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our investment strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties also may not necessarily reveal existing or potential problems, and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable or may be limited by floors and caps, and the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on our ability to recover the costs related to any potential problem could materially impact our financial condition and results of operations.

Ownership of our oil, gas and natural gas liquids production depends on good title to our property.

Good and clear title to our oil and gas properties is important. Although we will generally conduct title reviews before the purchase of most oil, gas, natural gas liquids and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim, which could result in a reduction or elimination of the revenue received by us from such properties.

Local and municipal laws could also result in increased costs and additional operating restrictions or delays.

In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing and related operations in particular.  In some jurisdictions, the authority of localities to regulate hydraulic fracturing has become contentious.  Courts have been asked to determine whether state regulatory schemes “pre-empt” local regulation.  The outcome of legal challenges to local efforts to regulate hydraulic fracturing depends in large part on the intent of the State legislature and the comprehensiveness of its statutory scheme.  If the right of municipalities to impose additional requirements is upheld, and municipalities elect to do so, local rules could impose additional constraints – such as siting and setback restrictions – and costs on our operations.

We must operate in accordance with comprehensive environmental laws that affect the manner, feasibility and cost of our operations.

Our operations are regulated extensively at the federal, state and local levels. Our operations, wells and other facilities are subject to stringent and complex federal, state and local environmental laws governing air emissions, water use and wastewater discharge, hazardous waste management and hazardous substance response. In some cases, we may be required to obtain environmental assessments, environmental impact studies, and/or plans of development before commencing drilling and production activities. Our activities may be subject to regulations regarding conservation practices. These regulations affect our operations and may limit the quantity of natural gas and oil we may produce and sell. Compliance with environmental laws will add to the costs of planning, designing, drilling, installing, operating and abandoning natural gas and oil wells.

32


 

Our ability to obtain, remove, treat, recycle or otherwise dispose of water will affect our production, and the cost of water treatment and disposal may affect our ability to make distributions.

Hydraulic fracturing requires large amounts of water and results in water discharges that must be treated, recycled or otherwise disposed. Environmental regulations governing the injection, withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our operations and financial performance. Although not anticipated by our general partner, we may need to drill our own water disposal wells. We currently use trucks to transport the water to water disposal wells or water treatment or recycling facilities, in certain areas, and pipe the water to disposal wells in other areas. If, however, we needed to drill our own disposal wells, there is a risk that we could not operate a gas production well at its full capacity until the required permit for the water disposal well was issued. Finally, if the environmental laws governing the management of produced waters become more stringent, they could restrict our ability to conduct hydraulic fracturing or increase our cost.

Rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

In 2012, USEPA established the NSPS rule for oil and natural gas production, transmission, and distribution, and also made significant revisions to the existing National Emission Standards for Hazardous Air Pollutants (“NESHAP”) rules for oil and natural gas production, transmission, and storage facilities. These rules require oil and natural gas production facilities to conduct “green completions” for hydraulic fracturing, which is recovering rather than venting the gas and natural gas liquids that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment.  Both the NSPS and NESHAP rules continue to evolve based on new information and changing environmental concerns.   President Trump’s March 28, 2017, Executive Order on Promoting Energy Independence and Economic Growth ordered federal agencies to revisit federal rules aimed at limiting methane emissions from oil and gas wells.  Initial efforts to revise or rescind standards for new or modified wells were invalidated by the courts but corrective rule-making initiated.  We believe it will be several years before those new rules are fully implemented.

Some states in which we operate are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations.

Compliance with new rules regulating air emissions from our operations could result in significant costs, including increased capital expenditures and operating costs, and could affect the results of our business.

Environmental laws may become more stringent, increasing the financial and managerial costs of compliance and, consequently, reducing our profitability.

The possibility exists that stricter environmental laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs. Failure to comply with environmental laws may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. States outside the geographic area in which we conduct our activities have imposed a variety of restrictions on hydraulic fracturing that could be adopted in jurisdictions in which we operate. State restrictions have included permitting, chemical disclosure, siting, seismicity, water withdrawal and disposal, and tank secondary containment requirements. If new restrictions such as these or others are imposed on our operations, we may (i) incur significant additional costs to comply, (ii) experience delays or curtailment in the pursuit of exploration, development or production activities, and (iii) perhaps even be precluded from drilling wells.

The federal government could take a more active role in regulating hydraulic fracturing, which could result in increased costs, operating restrictions or delays.

Presently, the hydraulic fracturing process, unless conducted on federal land, has not generally been subject to comprehensive regulation at the federal level. Presently, federal interests are primarily in the disclosure of fracturing fluid ingredients where fracturing occurs on federal lands and in air emissions from fracturing wells. If hydraulic fracturing were to become comprehensively regulated at the federal level, our fracturing activities could be significantly affected. Federal restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are able to produce. New environmental initiatives and regulations could include restrictions on the ability to conduct 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.  Also, the threat of climate change has resulted in increasing political risks in the United States, including climate-related pledges to ban hydraulic fracturing of oil and gas wells being made by certain candidates seeking the office of President of the United States in 2020. Additionally, Senator Bernie Sanders (D-VT), who is one of the presidential candidates that has pledged to ban hydraulic fracturing, introduced Senate Bill 3247 on January 28, 2020 that, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025.  Any of these environmental initiatives and regulations, including the proposed ban, could have a material adverse effect on our financial condition and results of operations.

33


 

We may not be able to secure all the authorizations required under environmental law to conduct drilling operations.

A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our leases. Under some laws, environmental organizations have the right to challenge production operations on grounds of environmental protection. In recent years, organized opposition has succeeded in curtailing certain drilling projects.

We may incur liability as the result of an accidental release of hazardous substances into the environment.

Our operations create the risk of inadvertent releases of hazardous substances into the environment, despite the exercise of reasonable caution. If such a release were to occur, we will be liable for the costs of responding to any such release, investigating the extent of its impacts and the cost of any remediation that may become necessary. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. We may not be able to recover remediation costs under our insurance policies.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, oil and NGLs we produce.

Future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.

With the issuance, on March 28, 2017, of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth, we believe it may take many years for new comprehensive federal policy aimed at greenhouse gas emissions to gel (see Item 1: Business—Environmental Matters and Regulation—Greenhouse Gas Regulation and Climate Change).  Given the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are “air pollutants” covered by the Clean Air Act) and scientific hurdles to overturning EPA’s endangerment finding, we believe some form of regulation will have to remain.  Regulations with the most direct impact on our operations concern controlling methane emissions from wells.  Rules that affect overall consumption of fossil fuels, and the mix of fossil fuels consumed, could also affect the demand for our products.  We believe, however, that federal agency implementation of the President’s Executive Order is some years away.  While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years.  Greater Congressional activity with respect to greenhouse gas emissions may be expected however as a result of Democrats regaining control of the House of Representatives.

In the absence of comprehensive federal climate change policy, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases.  States may also pursue additional regulation of our operations, including restrictions on methane emissions from new and existing wells and fracturing operations.  State and regional initiatives could result in significant costs, including increased capital expenditures and operating costs, affect the demand for our products, and could affect the results of our business.

If the current Administration’s initiatives to lessen the burden of environmental regulation on fossil fuel production and consumption become effective, they could result in greater overall supply of fossil fuels, reducing the price we receive for our output.

Pursuant to the President’s Executive Order on Promoting Energy Independence and Economic Growth, federal agencies have initiated several rule-makings to rescind and reconsider rules issued by the prior Administration that increased the overall stringency of environmental regulation of fossil fuel production and consumption.  The Administration has taken several steps to reverse the prior Administration’s policies that disadvantaged coal as a fuel for energy production, including withdrawing from the Paris Climate Agreement, a replacement of the 2015 Clean Power Plan, withdrawal of mercury limits on coal plants’ air emissions, lifting the prior Administration’s ban on new coal leases on federal lands and ending the review of the program’s greenhouse gas impacts, and withdrawing the “Waters of the United States” stream protection rule.  The Administration has opened more federal lands for oil and gas production, approved the construction of the Keystone Pipeline to facilitate refining of Alberta oil shale in the United States, licensed the Dakota Access Pipeline, and opened areas in the Arctic and Atlantic Ocean to drilling.  The Administration has initiated several rule-makings aimed at lessening the stringency of environmental regulation of oil and gas production.  Most of these actions are susceptible to, and can be expected to be the target of, court challenges.  If they are fully implemented, and if they have the effect of increasing the overall fuel supply, they could have the effect of diminishing demand for our natural gas and oil output.  Diminished demand could put additional downward pressure on the price of the natural gas and oil we produce.

34


 

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third- party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we will pay for their services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could subject us to liability and, if such failures are material, would require us to make alternative arrangements, which may not be available or which may involve increased costs.

Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our credit facility, our ability to make distributions to our unitholders will be inhibited. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

As of December 31, 2019 the lenders under the credit facility have no commitment to lend to us and we have a zero-dollar borrowing base under the credit facility, but it allows us to have the ability to enter into derivative contracts to manage our exposure to commodity price movements that will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and a first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we request a borrowing base redetermination and the lenders agree to establish the borrowing base and related commitments thereunder. If the borrowing base is redetermined to an amount greater than zero dollars, the credit facility would allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semiannually by our lenders in their sole discretion. If such borrowing base were to be established, it would be subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which takes into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding at that time in excess of the borrowing base. If we borrow under the credit facility and we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders. In addition, any limitations on our ability to borrow under our credit facility could inhibit our ability to make acquisitions, which could prevent us from being able to pay the target distribution.

 

A terrorist attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.

 

Terrorist activities, anti-terrorist efforts, and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Costs for insurance, recovery, remediation and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

 

Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation and increase compliance challenges.

 

We rely extensively on information technology systems, including Internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions.

 

35


 

Although we have implemented information technology controls and systems that are designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls we have installed may be breached. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations which may include drilling, completion, production and corporate functions. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including but not limited to, the following:

 

 

Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

 

 

Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

 

 

Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;

 

 

A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;

 

 

A cyber attack on third party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;

 

 

A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

 

 

A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;

 

 

A cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

 

 

A cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;

 

 

A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and

 

 

A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

 

All of the above could negatively impact our operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats 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 information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

If we are unable to obtain funding for future capital needs, cash distributions to our unitholders and the value of our properties could decline.

If we need additional capital in the future to improve or maintain our properties or for any other reason, we may have to obtain financing from sources beyond our funds from operations, such as borrowings. These sources of funding may not be available on attractive terms or at all. If we cannot procure additional funding for capital improvements, our properties may generate lower cash flows or decline in value, or both, which would limit our ability to make distributions to our unitholders and could reduce the value of your investment.

36


 

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from our operators than we or they currently anticipate.

As of December 31, 2018, a portion of our total estimated proved reserves were proved undeveloped or proved developed non-producing reserves and may not be ultimately developed or produced by our operators. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by our operators. Our reserve report assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our operators will develop the properties as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for our operators. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Because some wells may not return their drilling and completion costs, it may take many years to return your investment in cash, if ever.

Even if a well is completed by us and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. Thus, it may take many years to return your investment in cash, if ever.

Horizontal wells are more expensive and difficult to drill and complete than vertical wells.

Our general partner anticipates that some of the wells we will drill will be horizontal wells. Horizontal wells are more expensive to drill and complete than vertical wells because of increased costs associated with the drilling rigs needed to drill a horizontal well, including hydraulically fracturing the wells multiple times and using more casing in the wells. 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 of hydraulically fracturing wells results in higher costs, which may not result in greater recoverable reserves. In addition, horizontal wells will be more susceptible to mechanical problems associated with completing the wells, such as casing collapse and lost equipment, than vertical wells. Further, fracturing the formation in a horizontal well is more complicated than fracturing the same geological formation in a vertical well.

Our business depends on third-party natural gas and oil transportation and processing facilities and our ability to contract with those parties.

Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties and our ability to contract with those third parties. The lack of available capacity on these systems and facilities could require us to curtail or shut-in one or more producing wells or delay or discontinue drilling wells in an area where we have acquired projects. A curtailment or shut-in of production could materially reduce our cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow. Also, we may be unable to, or elect not to, purchase firm transportation on third party facilities and, in that event, our production transportation could be interrupted by other developers having firm arrangements. If any third-party pipelines and other facilities become partially or fully unavailable to transport or process our natural gas and oil production, or if the natural gas quality specifications for a natural gas pipeline or facility changes so as to restrict our ability to transport natural gas on those pipelines or facilities, we could be required to curtail or shut-in one or more of our wells and our revenues could decrease. Also, the disruption of third-party facilities due to maintenance and/or weather could limit our ability to market and deliver our natural gas, NGLs and oil production.

37


 

Participation with third parties in drilling wells may require us to pay additional costs and could subject our revenues to the claims of the third-party creditors.

Our general partner anticipates that we may participate with third parties in drilling some of our wells. In this regard, additional financial risks exist when the costs of drilling, equipping, completing, and operating wells are shared by more than one person. If we pay our share of the costs, but another interest owner does not pay its share of the costs, then we would have to pay the costs of the defaulting party. In this event, we would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, cover all of the additional costs paid by us.

If we are not the actual operator of the well for all of the working interest owners of the well, then there is a risk that our general partner will not be able to supervise the third-party operator closely enough, and that decisions related to the following would be made by the third-party operator, which may not be in our best interests or the best interests of our limited partners:

 

how the well is operated;

 

expenditures related to the well; and

 

possibly the marketing of the natural gas and oil production from the well.

Further, the third-party operator may have financial difficulties and fail to pay for materials or services on the wells it drills or operates, which would cause us to incur extra costs in discharging materialmen’s and workmen’s liens. In this regard, we may not be the operator of a well for all of the working interest owners of the well if we own less than a 50.00% working interest in the well, or if we acquired the working interest in the well from a third party under arrangements that required the third party to be named operator.

Federal Income Tax Risks

Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If we were to become subject to entity-level taxation for federal or state income tax purposes, taxes paid would reduce the amount of cash available for distribution.

Although the anticipated tax benefits of an investment in us depend largely on us being treated as a partnership for federal income tax purposes, we have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us. In this regard, current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. Also, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

Following a listing event, 90% or more of our gross income for every taxable year must be qualifying income, as defined in Section 7704 of the Code, in order to avoid being treated as a corporation for federal income tax purposes. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof) or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise be subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is 21% for taxable years beginning after December 31, 2018, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and none of our income, gain, loss, deduction and credit would flow through to you. If a tax were imposed on us as a corporation, our cash available for distribution could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to you, and therefore result in a substantial reduction in the value of our securities.

Changes in the law may reduce your tax benefits from an investment in us.

Your tax benefits from an investment in us may be affected by changes in the tax laws. For example, from time to time members of Congress have proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including your option to amortize intangible drilling costs over a 60 month period) and the passive activity exception for working interests. These proposals may or may not be enacted into law.

38


 

Limited partners need passive income to use their partnership deductions that exceed the income from us.

A limited partner’s share of our net losses will be passive losses that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, you may not have enough passive income from us or net passive income from your other passive activities, if any, to be offset by a portion or all of your passive deductions from us. However, any unused passive loss from us may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Also, except as described below, the passive activity limitations on your share of our losses do not apply to you if you invest in us and you are a corporation taxable under Subchapter C of the Code, which:

 

is not a personal service corporation or a closely held corporation;

 

is a personal service corporation in which employee-owners hold 10% (by value) or less of the stock, but is not a closely held corporation; or

 

is a closely held corporation (that is, five or fewer individuals own more than 50% by value of the stock), but is not a personal service corporation in which employee-owners own more than 10% by value of the stock, in which case you may use your passive losses to offset your net active income (calculated without regard to your passive activity income and losses or portfolio income and losses).

You may owe taxes in excess of your cash distributions from us.

You may become subject to income tax liability for your share of our income in any taxable year in an amount that is greater than the cash you receive from us in that taxable year. For example:

 

if we borrow money, your share of our revenues used to pay principal on the loan will be included in your income from us and will not be deductible;

 

income from sales of natural gas and oil may be included in your income from us in one tax year, even though payment is not actually received by us and, thus, cannot be distributed to you, until the next tax year;

 

if there is a deficit in your capital account, we may allocate income or gain to you even though you do not receive a corresponding distribution of our revenues;

 

our revenues may be expended by our general partner for nondeductible costs or retained by us to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells, which will reduce your cash distributions from us without a corresponding tax deduction; and

 

the taxable disposition of our property or your common units may result in income tax liability to you in excess of the cash you receive from the transaction.

In addition, under the recently enacted tax reform law known as the Tax Cuts and Jobs Act, if we borrow money and pay interest, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a limited partner’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

You and the other investors in us may be subject to state and local taxes and tax return filing requirements as a result of investing in us.

In addition to U.S. federal income taxes, you and the other investors will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes and tax return filing requirements that are imposed by the various jurisdictions in which we drill wells or otherwise do business now or in the future, even if you do not reside in any of those jurisdictions. Substantially all of our income is currently generated in Texas, although we may drill wells in other states as well. It is your responsibility to file all federal, foreign, state and local tax returns that may be required of you. In this regard, our tax counsel has not rendered an opinion on any foreign, state or local tax consequences of an investment in us.

Your tax benefits from an investment in us are not contractually protected.

An investment in us does not give you any contractual protection against the possibility that part or all of the intended tax benefits of your investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement for the tax treatment of your investment in us. You have no right to rescind your investment in us or to receive a refund of any of your investment in us if a portion or all of the intended tax consequences of your investment in us is ultimately disallowed by the IRS or the courts. Also, none of the fees paid by us to our general partner, its affiliates or independent third-parties are refundable or contingent on whether the intended tax consequences of your investment in us are ultimately sustained if challenged by the IRS.

39


 

Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and IRAs, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. If you are a tax-exempt entity, you should consult your tax advisor before investing in our common units.

 

We may be required to deduct and withhold certain amounts upon transfers of common units by non-U.S. persons.

Under the recently enacted tax reform law, if a limited partner sells or otherwise disposes of a common unit, the transferee is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld.

If the IRS makes audit adjustments to our income tax returns for taxable years beginning after 2017, the IRS (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our limited partners may be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, the IRS may collect any resulting taxes (including any applicable penalties and interest) directly from us (rather than our general partner and our limited partners). Certain states in which we own assets and conduct business may adopt the IRS approach or apply similar rules.

We will generally have the ability to shift any such tax liability (including penalties and interest) to our general partner and our limited partners in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our limited partners might be substantially reduced.

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our limited partners in accordance with their interests in us during the taxable year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment owed by us by reducing the suspended passive loss carryovers of our limited partners (without any compensation from us to such limited partners), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected limited partners.

An IRS audit of us may result in an IRS audit of your personal federal income tax returns.

The IRS may audit our annual federal information income tax returns, particularly since our investors will be eligible to claim deductions for intangible drilling costs and, with respect to wells drilled, completed and placed in service by us, depreciation of qualified equipment costs. If we are audited, the IRS also may audit your personal federal income tax returns, including prior years’ returns and items that are unrelated to us. Any adjustments made by the IRS to our federal information income tax returns could lead to adjustments on your personal federal income tax returns and could reduce the amount of your deductions from us.

Upon a listing event, we will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our limited partners. The IRS may challenge this treatment, which could adversely affect the value of your common units.

When we issue additional equity interests or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our limited partners and general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we may make many of the fair market value estimates ourselves using a methodology based on the market value of our equity interests as a means to measure the fair market value of our assets. The methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain holders of common units and our general partner, which may be unfavorable to you. Moreover, under current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge the valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of the holders of common units.

40


 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our limited partners. It also could affect the amount of gain on the sale of equity interests by you and could have a negative impact on the value of our equity interests or result in audit adjustments to the tax returns of our limited partners without the benefit of additional deductions.

 

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

ITEM 2:

PROPERTIES

See Item 1: Business.

ITEM 3:

LEGAL PROCEEDINGS

We are a party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See Part II, Item 8: Financial Statements and Supplementary Data - Note 8.

ITEM 4:

MINE SAFETY DISCLOSURES

Not applicable.

41


 

PART II

ITEM 5:

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common units are currently not listed on any exchange or over-the-counter market. The common units have not been approved for quotation or trading on a national securities exchange. Subject to the approval of the board of directors of our general partner, our Partnership Agreement gives our general partner the right to cause the common units to be listed on a national securities exchange if our general partner determines that the common units meet the listing requirements of a national securities exchange. No assurances can be made that the common units will be listed on a national securities exchange, and even if listed an active market for the common units may not develop.

At the close of business on April 16, 2020, there were 2,979 holders of record.

On November 2, 2016, the board of directors of our general partner determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain our cash flow and reinvest in our business and assets. At this time, we can provide no certainty as to when or if distributions will be reinstituted.  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.  

Securities Authorized for Issuance Under Equity Compensation Plans

None.

42


 

ITEM 6:

SELECTED FINANCIAL DATA

The following table presents our selected historical consolidated financial data as of and for the periods indicated and should be read in conjunction with Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8: Financial Statements and Supplementary Data.

 

 

 

 

Years Ended December 31,

 

 

 

 

2019

 

 

2018

 

2017

 

2016

 

2015

 

 

 

 

 

 

 

(in thousands, except per unit data)

 

Statement of operations data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

82

 

 

$

225

 

$

322

 

$

358

 

$

518

 

Oil revenue

 

 

5,791

 

 

 

9,708

 

 

7,117

 

 

11,121

 

 

10,959

 

NGLs revenue

 

 

188

 

 

 

508

 

 

402

 

 

372

 

 

369

 

Gain (loss) on mark-to-market derivatives

 

 

 

 

 

(381

)

 

310

 

 

(780

)

 

862

 

Total revenues

 

 

6,061

 

 

 

10,060

 

 

8,151

 

 

11,071

 

 

12,708

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas and oil production

 

 

2,512

 

 

 

3,486

 

 

2,528

 

 

2,660

 

 

2,229

 

General and administrative

 

 

1,261

 

 

 

655

 

 

813

 

 

571

 

 

685

 

General and administrative – affiliate

 

 

3,206

 

 

 

3,291

 

 

4,131

 

 

9,347

 

 

12,054

 

Depreciation, depletion and amortization

 

 

3,607

 

 

 

5,874

 

 

3,576

 

 

14,868

 

 

8,951

 

Asset impairment

 

 

10,982

 

 

 

41,762

 

 

 

 

41,879

 

 

7,346

 

Total costs and expenses

 

 

21,568

 

 

 

55,068

 

 

11,048

 

 

69,325

 

 

31,265

 

Operating loss

 

$

(15,507

)

 

$

(45,008

)

$

(2,897

)

$

(58,254

)

$

(18,557

)

Loss on asset sales

 

 

(33

)

 

 

 

 

 

 

 

 

 

Other loss

 

 

 

 

 

 

 

 

 

(5,383

)

 

 

Net loss

 

$

(15,540

)

 

$

(45,008

)

$

(2,897

)

$

(63,637

)

 

(18,557

)

Balance sheet data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net

 

$

9,682

 

 

$

24,686

 

$

65,293

 

$

68,899

 

$

125,286

 

Total assets

 

 

12,955

 

 

 

28,920

 

 

74,219

 

 

78,500

 

 

160,267

 

Total partners’ capital

 

 

11,364

 

 

 

26,904

 

 

71,912

 

 

74,809

 

 

149,387

 

Cash flow data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in) operating

   activities

 

$

(1,284

)

 

$

2,180

 

$

(350

)

$

8,105

 

$

(26,890

)

Net cash used in investing activities

 

 

(20

)

 

 

(6,873

)

 

 

 

(6,602

)

 

(71,700

)

Net cash provided by (used in) financing

   activities

 

 

 

 

 

 

 

 

 

(16,238

)

 

88,506

 

Capital expenditures

 

 

 

 

 

6,873

 

 

 

 

6,602

 

 

29,222

 

 

 

43


 

ITEM 7:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 6: Selected Financial Data” and “Item 8: Financial Statements and Supplemental Data”, which contains our consolidated financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and in “Item 1A: Risk Factors”. We believe the assumptions underlying the consolidated financial statements are reasonable. However, our consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.

BUSINESS OVERVIEW

We are a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and controls us.

Atlas Energy Group, LLC (“ATLS”), a Delaware limited liability company, manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.

MANAGEMENT OVERVIEW AND OUTLOOK

Since our inception in 2013, we have developed into a company with a core position in the Eagle Ford Shale in south Texas generating stable cash flows, despite a significant decline in oil and natural gas prices.  While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses.  At December 31, 2019, we had $2.2 million of cash on our balance sheet and no debt. Our general and administrative expenses increased $0.6 million to $4.5 million for the year ended December 31, 2019 from $3.9 million for the year ended December 31, 2018.

During the year ended December 31, 2018, we deployed $6.9 million of cash on hand to drill and complete one Eagle Ford Shale well that turned in-line during May 2018. The well has increased our production and provided additional cash flow to our business. With this additional well, we have enhanced ability to generate positive cash flow from our operations, grow our cash balance, and take advantage of opportunities to drill new Eagle Ford Shale wells or take on other strategic initiatives and transactions should favorable conditions arise.

While we manage the company on a daily basis to optimize operating results, we also continue to explore ways to strategically grow and transform the company. Quarterly, we consider our ability to make distributions to unitholders; however, based on the company’s financial position and cash flows, we have not yet elected to resume making distributions following the suspension in November 2016. We continue to explore opportunities to drill additional wells across our Eagle Ford Shale locations.  Our ability to convert our locations into cash-flowing wells may be improved by raising additional capital, but we have limited avenues to do so at this time.  We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders.  We will continue to vigorously pursue all options to maximize returns to our investors.

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by key trends in natural gas and oil production markets. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Throughout 2019 and 2018, the natural gas, oil and natural gas liquids commodity price markets have been marked by volatility. While we anticipate high levels of exploration and production activities over the long-term in the area in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

44


 

Our future gas and oil reserves, production, cash flow, our ability to make payments on our obligations and our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we would not have access to sufficient capital, our ability to drill and acquire more reserves would be negatively impacted.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. We have established production positions in the following areas:

 

the Eagle Ford Shale in south Texas, an oil-rich area, in which we acquired acreage in November 2014, where we derive over 99% of our production volumes and 98% of our revenues;

 

the Marble Falls play in the Fort Worth Basin in northern Texas, in which we own acreage and producing wells, which contains liquids-rich natural gas and oil. In January 2019, we sold our Marble Falls position, which resulted in a gain of $15 thousand after customary purchase price adjustments; and

 

the Mississippi Lime play in northwestern Oklahoma, an oil and NGL-rich area. In July 2019, we sold our Mississippi Lime position, which resulted in a loss of $48 thousand after customary purchase price adjustments.

Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production volumes per day for the periods indicated:

 

 

 

Years Ended December 31,

 

 

 

2019

 

2018

 

2017

 

Total production volumes per day:

 

 

 

 

 

 

 

 

 

Natural gas (Boed)

 

31

 

 

51

 

 

52

 

Oil (Bpd)

 

274

 

 

396

 

 

392

 

NGLs (Bpd)

 

38

 

 

57

 

 

55

 

Total (Boed)

 

343

 

 

504

 

 

499

 

Total production volumes:

 

 

 

 

 

 

 

 

 

Natural gas (MBoe)

 

11

 

 

19

 

 

19

 

Oil (MBbls)

 

100

 

 

145

 

 

143

 

NGLs (MBbls)

 

14

 

 

20

 

 

20

 

Total (MBoe)

 

125

 

 

184

 

 

182

 

 

45


 

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for oil. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production, along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, for the periods indicated:

 

 

 

Years Ended December 31,

 

 

 

2019

 

2018

 

2017

 

Production revenues (in thousands):(1)

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

82

 

$

225

 

$

322

 

Oil revenue

 

 

5,791

 

 

9,708

 

 

7,117

 

NGLs revenue

 

 

188

 

 

508

 

 

402

 

Total revenues

 

$

6,061

 

$

10,441

 

$

7,841

 

Average sales price, unhedged:

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

1.21

 

$

2.03

 

$

2.83

 

Oil (per Bbl)

 

$

57.99

 

$