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EX-32.1 - EX-32.1 - Triangle Petroleum Corptpc-20160430ex3211c9cd8.htm
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EX-31.1 - EX-31.1 - Triangle Petroleum Corptpc-20160430ex311bfeb7c.htm
EX-10.2 - EX-10.2 - Triangle Petroleum Corptpc-20160430ex102b01b81.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

 

For the quarterly period ended April 30, 2016

 

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

ACT OF 1934

 

For the transition period from _________ to _________

 

Commission file number 001-34945

 

TRIANGLE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

Delaware

   

 

98-0430762

(State or Other Jurisdiction of

Incorporation or Organization)

   

 

(I.R.S. Employer

Identification No.)

 

 

1200 17th Street, Suite 2500

Denver, CO 80202

(Address of Principal Executive Offices)

 

(303) 260-7125

(Registrant’s telephone number, including area code)

 

(Former name, former address and former fiscal year, if changed since last report)

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes   No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

 

 

 

 Large accelerated filer

 Accelerated filer

 Non-accelerated filer

 Smaller reporting company

(Do not check if a smaller reporting company)

   

 

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 6, 2016, there were 76,305,321 shares of the registrant’s common stock outstanding.

 

 

 

 


 

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

 

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED APRIL 30, 2016

 

April

 

 

 

   

   

   

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 

 

 

 

 

PART I.  FINANCIAL INFORMATION 

 

 

 

 

   

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

   

   

   

 

   

   

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

   

   

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

   

   

   

 

   

   

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

   

   

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)

   

   

   

 

   

   

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   

   

   

   

   

ITEM 2.

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

25 

 

 

 

 

   

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

36 

   

   

   

 

   

ITEM 4.

CONTROLS AND PROCEDURES

37 

   

   

   

 

PART II.  OTHER INFORMATION 

38 

   

   

   

 

   

ITEM 1.

LEGAL PROCEEDINGS

38 

 

 

 

 

   

ITEM 1A.

RISK FACTORS

38 

 

 

 

 

   

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

39 

 

 

 

 

   

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

40 

 

 

 

 

   

ITEM 4.

MINE SAFETY DISCLOSURES 

40 

 

 

 

 

   

ITEM 5.

OTHER INFORMATION

40 

 

 

 

 

   

ITEM 6.

EXHIBITS

41 

   

   

   

 

SIGNATURES 

42 

 

 

 

 

i


 

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “could,” “would,” “will,” “may,” “can,” “continue,” “potential,” “likely,” “should,” and the negative of these terms or other comparable terminology, often identify forward-looking statements. Statements in this quarterly report that are not statements of historical facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”).

 

These forward-looking statements include, but are not limited to, statements about:

 

·

future capital expenditures and performance;

·

future operating results;

·

future commodity prices;

·

future ability to borrow or repay indebtedness;

·

results of evaluation and implementation of strategic alternatives;

·

anticipated drilling and development;

·

drilling results;

·

results of acquisitions;

·

relationships with partners; and

·

plans for our subsidiaries.

 

Actual results or developments may be different than we anticipate or may have unanticipated consequences to, or effects on, us or our business or operations. All of the forward-looking statements made in this report are qualified by the discussion of risks and uncertainties under “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended January 31, 2016, and in our other public filings with the SEC. Although the expectations reflected in the forward-looking statements are based on our current beliefs and expectations, undue reliance should not be placed on any such forward-looking statements due to the risks and uncertainties noted above and because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

 

 

 

 

 

1


 

PART I.  FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS (UNAUDITED).

 

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

January 31, 2016

    

April 30, 2016

ASSETS

CURRENT ASSETS

 

 

 

 

 

 

Cash and cash equivalents

 

$

115,769

 

$

197,648

Accounts receivable

 

 

53,302

 

 

53,786

Commodity derivatives

 

 

12,370

 

 

6,681

Other current assets

 

 

10,046

 

 

10,890

Total current assets

 

 

191,487

 

 

269,005

 

 

 

 

 

 

 

PROPERTY, PLANT AND EQUIPMENT, AT COST

 

 

 

 

 

 

Oil and natural gas properties, full cost method of accounting

 

 

 

 

 

 

Proved properties

 

 

1,372,480

 

 

1,385,852

Unproved properties and properties under development, not being amortized

 

 

78,367

 

 

77,238

Total oil and natural gas properties

 

 

1,450,847

 

 

1,463,090

Accumulated amortization

 

 

(1,044,307)

 

 

(1,132,762)

Net oil and natural gas properties

 

 

406,540

 

 

330,328

Oilfield services equipment, net

 

 

48,445

 

 

44,147

Other property and equipment, net

 

 

42,874

 

 

40,498

Net property, plant and equipment

 

 

497,859

 

 

414,973

 

 

 

 

 

 

 

OTHER ASSETS

 

 

 

 

 

 

Equity investment

 

 

45,600

 

 

45,700

Commodity derivatives

 

 

9,012

 

 

2,916

Debt issuance costs

 

 

3,877

 

 

3,604

Other

 

 

5,313

 

 

5,218

Total other assets

 

 

63,802

 

 

57,438

 

 

 

 

 

 

 

Total assets

 

$

753,148

 

$

741,416

 

See notes to condensed consolidated financial statements.

 

2


 

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

January 31, 2016

    

April 30, 2016

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)

CURRENT LIABILITIES

 

 

 

 

 

 

Accounts payable and accrued capital expenditures

 

$

67,339

 

$

64,042

Other accrued liabilities

 

 

34,065

 

 

32,308

Current portion of long-term debt

 

 

114,088

 

 

826,797

Interest payable

 

 

1,700

 

 

8,374

Total current liabilities

 

 

217,192

 

 

931,521

 

 

 

 

 

 

 

LONG-TERM LIABILITIES

 

 

 

 

 

 

Long-term debt

 

 

789,043

 

 

155,964

Other

 

 

11,495

 

 

10,850

Total liabilities

 

 

1,017,730

 

 

1,098,335

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS' EQUITY (DEFICIT)

 

 

 

 

 

 

Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,807,111 and 76,300,464 shares issued and outstanding at January 31, 2016 and April 30, 2016, respectively

 

 

1

 

 

1

Additional paid-in capital

 

 

557,757

 

 

559,527

Retained earnings (accumulated deficit)

 

 

(822,340)

 

 

(916,447)

Total stockholders' equity (deficit)

 

 

(264,582)

 

 

(356,919)

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity (deficit)

 

$

753,148

 

$

741,416

 

See notes to condensed consolidated financial statements.

 

 

3


 

Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(In thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

 

    

2015

    

2016

REVENUES:

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

47,778

 

$

24,852

Oilfield services

 

 

70,510

 

 

19,520

Total revenues

 

 

118,288

 

 

44,372

EXPENSES:

 

 

 

 

 

 

Lease operating expenses

 

 

10,923

 

 

8,602

Gathering, transportation and processing

 

 

6,348

 

 

5,608

Production taxes

 

 

4,787

 

 

2,079

Depreciation and amortization

 

 

37,792

 

 

14,888

Impairment of oil and natural gas properties

 

 

192,000

 

 

79,000

Accretion of asset retirement obligations

 

 

57

 

 

123

Oilfield services

 

 

64,226

 

 

16,671

General and administrative, net of amounts capitalized

 

 

14,859

 

 

11,323

Total operating expenses

 

 

330,992

 

 

138,294

 

 

 

 

 

 

 

INCOME (LOSS) FROM OPERATIONS

 

 

(212,704)

 

 

(93,922)

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

Interest expense, net

 

 

(9,106)

 

 

(10,792)

Amortization of debt issuance costs

 

 

(616)

 

 

(957)

Gain on extinguishment of debt

 

 

 —

 

 

21,180

Realized commodity derivative gains (losses)

 

 

19,468

 

 

2,104

Unrealized commodity derivative gains (losses)

 

 

(33,442)

 

 

(11,785)

Equity investment income (loss)

 

 

188

 

 

(48)

Impairment of equity investment

 

 

2,880

 

 

 —

Other income (expense), net

 

 

(308)

 

 

113

Total other income (expense)

 

 

(20,936)

 

 

(185)

 

 

 

 

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

 

 

(233,640)

 

 

(94,107)

 

 

 

 

 

 

 

INCOME TAX PROVISION (BENEFIT)

 

 

(53,441)

 

 

 —

 

 

 

 

 

 

 

NET INCOME (LOSS)

 

$

(180,199)

 

$

(94,107)

   

 

 

 

 

 

 

Earnings (loss) per common share outstanding:

 

 

 

 

 

 

Basic

 

$

(2.39)

 

$

(1.24)

Diluted

 

$

(2.39)

 

$

(1.24)

   

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

Basic

 

 

75,256

 

 

76,090

Diluted

 

 

75,256

 

 

76,090

 

See notes to condensed consolidated financial statements.

 

 

4


 

Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

 

 

 

2015

    

2016

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

Net income (loss)

 

$

(180,199)

 

$

(94,107)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

Depreciation, amortization and accretion

 

 

37,849

 

 

15,011

Impairment of oil and natural gas properties

 

 

192,000

 

 

79,000

Share-based compensation

 

 

2,508

 

 

1,812

Interest expense paid-in-kind on 5% convertible note

 

 

1,699

 

 

1,785

Amortization of debt issuance costs

 

 

616

 

 

957

Gain on extinguishment of debt

 

 

 —

 

 

(21,180)

Unrealized commodity derivative (gains) losses

 

 

33,442

 

 

11,785

Equity investment (income) loss

 

 

(188)

 

 

48

Gain on Caliber capital transaction

 

 

(2,880)

 

 

 —

Deferred income taxes

 

 

(53,441)

 

 

 —

Other

 

 

 —

 

 

(82)

Changes in related current assets and current liabilities:

 

 

 

 

 

 

Accounts receivable

 

 

47,090

 

 

(484)

Other current assets

 

 

4,347

 

 

(824)

Accounts payable and accrued liabilities

 

 

(42,955)

 

 

1,042

Asset retirement expenditures

 

 

(5)

 

 

(30)

Other

 

 

(628)

 

 

(790)

Cash provided by (used in) operating activities

 

 

39,255

 

 

(6,057)

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

Oil and natural gas property expenditures

 

 

(74,834)

 

 

(11,034)

Acquisitions of oil and natural gas properties

 

 

(222)

 

 

(157)

Purchases of oilfield services equipment

 

 

(5,299)

 

 

(496)

Purchases of other property and equipment

 

 

(2,251)

 

 

(19)

Sale of oil and natural gas properties

 

 

6,000

 

 

408

Proceeds from sale of equipment

 

 

 —

 

 

1,174

Cash used in investing activities

 

 

(76,606)

 

 

(10,124)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

Proceeds from credit facilities

 

 

51,000

 

 

103,700

Repayments of credit facilities

 

 

(29,871)

 

 

 —

Repayments of other notes and mortgages payable

 

 

(125)

 

 

(679)

Early extinguishment of repurchased debt

 

 

 —

 

 

(4,640)

Debt issuance costs

 

 

(890)

 

 

(59)

Payments to settle tax on vested restricted stock units

 

 

(357)

 

 

(187)

Distributions to RockPile B Unit holders

 

 

 —

 

 

(75)

Cash provided by financing activities

 

 

19,757

 

 

98,060

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

 

(17,594)

 

 

81,879

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

 

67,871

 

 

115,769

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

50,277

 

$

197,648

 

See notes to condensed consolidated financial statements.

 

 

5


 

Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity (Deficit) (Unaudited)

(in thousands, except share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retained

 

Total

 

 

Shares of

 

Common

 

Additional

 

Earnings

 

Stockholders'

 

 

Common

 

Stock at

 

Paid-in

 

(Accumulated

 

Equity

 

    

Stock

    

Par Value

    

Capital

    

Deficit)

    

(Deficit)

Balance - January 31, 2016

 

75,807,111

 

$

1

 

$

557,757

 

$

(822,340)

 

$

(264,582)

Vesting of restricted stock units (net of shares surrendered for taxes)

 

493,353

 

 

 —

 

 

(187)

 

 

 —

 

 

(187)

Share-based compensation

 

 —

 

 

 —

 

 

2,032

 

 

 —

 

 

2,032

Distributions to RockPile B Unit holders

 

 —

 

 

 —

 

 

(75)

 

 

 —

 

 

(75)

Net income (loss) for the period

 

 —

 

 

 —

 

 

 —

 

 

(94,107)

 

 

(94,107)

Balance - April 30, 2016

 

76,300,464

 

$

1

 

$

559,527

 

$

(916,447)

 

$

(356,919)

 

See notes to condensed consolidated financial statements.

 

 

 

6


 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

 

Description of Business. Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) is an independent energy holding company with three principal lines of business: oil and natural gas exploration, development, and production; oilfield services; and midstream services.

 

We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana. Our core focus area is predominantly located in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”).

 

RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, provides oilfield and complementary well completion services to oil and natural gas exploration and production companies predominantly in the Williston and Permian Basins.

 

Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund, provides oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin.

 

The Company, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada. Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia. Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage. Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012.

 

Basis of Presentation. These unaudited condensed consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”), and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts.

 

Certain information and footnote disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. We believe the disclosures made are adequate to make the information not misleading. We recommend that these unaudited condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended January 31, 2016, as filed with the SEC (“Fiscal 2016 Form 10-K”). In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company’s interim results have been reflected. All such adjustments are considered to be of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

 

No condensed consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented.

 

Liquidity and Ability to Continue as a Going Concern. The accompanying condensed consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. As such, the accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

 

Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, continued low commodity prices are expected to result in significantly lower levels of cash flow from operating activities in the future and have limited the Company’s ability to access capital markets. These factors and the

7


 

TUSA and RockPile covenant compliance issues discussed below raise substantial doubt about the Company’s ability to continue as a going concern.

 

TUSA Liquidity and Covenants. On April 28, 2016, TUSA’s credit facility lenders significantly reduced the borrowing base under the credit facility from $350.0 million to $225.0 million, which was a greater reduction than we had anticipated. As of April 30, 2016, TUSA had $347.5 million of outstanding borrowings and $2.5 million of outstanding letters of credit under the credit facility, or $125.0 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). TUSA had cash on hand of approximately $152.3 million at April 30, 2016. TUSA elected to repay the borrowing base deficiency in three equal monthly installments of $41.7 million, the first payment of which was paid on May 31, 2016. Any non-payment of the borrowing base deficiency could result in an event of default.

 

As of April 30, 2016, TUSA was in breach of the credit facility’s minimum current ratio requirement. On May 27, 2016, TUSA entered into a Forbearance and Amendment No. 2 to Second Amended and Restated Credit Agreement (the “TUSA Forbearance Amendment”) with its credit facility lenders, pursuant to which the lenders agreed to forbear exercising any rights or remedies available to them arising from any breach related to the minimum required current ratio or the senior secured leverage ratio that may have occurred as of April 30, 2016. The forbearance is effective until the earlier of July 8, 2016 or specified forbearance termination events including the commencement of any bankruptcy or reorganization proceeding under applicable bankruptcy or insolvency law.

 

Although it is difficult to forecast future operations in this low commodity price environment, TUSA may not  comply with all of the financial covenants contained in its credit facility in future periods unless those requirements are waived or amended or unless TUSA can obtain new capital or equity cure financing. The greater than expected reduction in the borrowing base contributed to the breach of the minimum current ratio requirement at April 30, 2016, and will have a negative impact on TUSA’s expected financial covenant performance for the remainder of fiscal year 2017 and increase the amount of any needed equity cure. TUSA remains in discussions regarding strategic alternatives, but there are no guarantees these discussions or negotiations will be successful. If TUSA is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, TUSA’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable after the forbearance period ends. If this happens, the Company does not currently have sufficient liquidity to make the equity cures for the credit facility that we expect may be necessary in the next 12 months.

 

As more fully described in Note 3, if the TUSA credit facility lenders declare any financial covenant breach or non-payment of the borrowing base deficiency an event of default, there are cross-default provisions in the Indenture of the TUSA 6.75% Notes (as defined below) that could enable holders of the TUSA 6.75% Notes to also declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable. TUSA does not have sufficient liquidity to repay the credit facility and the TUSA 6.75% Notes. Therefore, the condensed consolidated balance sheet reflects all of the amounts outstanding under the TUSA credit facility and the balance outstanding of the TUSA 6.75% Notes as current liabilities as of April 30, 2016. TUSA could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of TUSA. Triangle has not guaranteed TUSA’s obligations under the TUSA credit facility or the TUSA 6.75% Notes.

 

RockPile Liquidity and Covenants. On April 13, 2016, RockPile entered into Amendment No. 2 to Credit Agreement (the “RockPile Waiver Amendment”), which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 and April 30, 2016. Following the execution of the RockPile Waiver Amendment, RockPile is precluded from drawing additional funds absent further amendment of the facility. Beginning with the second quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing as discussed further in Note 3. RockPile remains in discussions regarding strategic alternatives, but the success of these discussions and negotiations is uncertain. In addition, if RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the condensed consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of April 30, 2016. RockPile could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of RockPile.

 

8


 

Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default.

 

Triangle Liquidity. Triangle recently engaged certain professional advisors to assist it in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including: (i) obtaining waivers or amendments from RockPile’s and TUSA’s lenders; (ii) obtaining additional sources of capital from asset sales, issuances of debt or equity securities, debt for equity swaps, or any combination thereof; and (iii) pursuing in- and out-of-court restructuring transactions. In connection with a debt restructuring or refinancing, we may seek to convert a significant portion of our outstanding debt to equity, including the exchange of debt for shares of our common stock or for shares of TUSA or RockPile. In addition, we may seek to reduce our cash interest cost and extend debt maturity dates by negotiating the exchange of outstanding debt for new debt with modified terms or other measures. While we anticipate engaging in active dialogue with our creditors, at this time we are unable to predict the outcome of such discussions, the outcome of any strategic transactions that we may pursue or whether any such efforts will be successful.

 

As a result of the above, substantial doubt exists regarding the ability of Triangle to continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business.

 

Use of Estimates. In the course of preparing its condensed consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of unproved properties, investment in equity method investees and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued expenses and related liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these condensed consolidated financial statements.

 

Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying condensed consolidated financial statements. All significant intercompany transactions and balances are eliminated in consolidation. Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. The investment in Caliber is accounted for utilizing the equity method of accounting.

 

Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations.

 

At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties.

 

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West

9


 

Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

 

 

 

 

 

 

 

 

 

 

 

 

 

January 31, 2016

 

April 30, 2016

Oil (per Bbl)

$

48.93

 

$

45.16

Natural gas (per MMbtu)

$

2.53

 

$

2.33

Natural gas liquids (per Bbl)

$

24.97

 

$

23.10

 

We recognized impairments to our proved oil and natural gas properties of $79.0 million for the quarter ended April 30, 2016, primarily due to the decline in oil, natural gas and natural gas liquids prices. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further. The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids (“NGL”) prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and natural gas properties is not reversible at a later date.

 

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

 

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment consisted of the following as of:

 

 

 

 

 

 

 

 

 

 

(in thousands)

    

January 31, 2016

    

April 30, 2016

Oilfield services equipment

 

$

110,992

 

$

111,644

Accumulated depreciation

 

 

(63,367)

 

 

(68,229)

Depreciable assets, net

 

 

47,625

 

 

43,415

Assets not placed in service

 

 

820

 

 

732

Total oilfield services equipment, net

 

$

48,445

 

$

44,147

 

 

 

 

 

 

 

Land

 

$

6,838

 

$

6,744

Building and leasehold improvements

 

 

37,149

 

 

37,083

Vehicles

 

 

5,036

 

 

5,042

Software, computers and office equipment

 

 

7,451

 

 

6,558

Capital leases

 

 

944

 

 

90

Accumulated depreciation

 

 

(14,939)

 

 

(15,229)

Depreciable assets, net

 

 

42,479

 

 

40,288

Assets not placed in service

 

 

395

 

 

210

Total other property and equipment, net

 

$

42,874

 

$

40,498

 

Income Taxes. The Company computes its quarterly tax provision using the effective tax rate method based on applying the anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

 

The carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $779.0 million for fiscal year 2016. This impairment resulted in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $286.0 million at January 31, 2016. These losses and expected future losses resulting from the current low commodity price environment were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30, 2016, since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

 

10


 

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

 

In the first quarter of fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense or for state income taxes.

 

As of April 30, 2016, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company’s position during the first three months of fiscal year 2017. Given the substantial net operating loss carryforwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely only adjust net operating loss carryforwards.

 

Earnings per Share. Basic earnings per common share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted earnings per common share reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units. The assumed proceeds are adjusted for income tax effects. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

 

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

 

2015

    

2016

Dilutive

 

 

 —

 

 

 —

Anti-dilutive shares

 

 

10,910

 

 

8,536

 

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands, except per share data)

    

2015

    

2016

Net income (loss) attributable to common stockholders

 

$

(180,199)

 

$

(94,107)

Effect of 5% convertible note conversion

 

 

 —

 

 

 —

Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion

 

$

(180,199)

 

$

(94,107)

 

 

 

 

 

 

 

Basic weighted average common shares outstanding

 

 

75,256

 

 

76,090

Effect of dilutive securities

 

 

 —

 

 

 —

Diluted weighted average common shares outstanding

 

 

75,256

 

 

76,090

 

 

 

 

 

 

 

Basic net income (loss) per share

 

$

(2.39)

 

$

(1.24)

Diluted net income (loss) per share

 

$

(2.39)

 

$

(1.24)

 

11


 

Adopted and Recently Issued Accounting Pronouncements.  In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 201409”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; however, in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 201409 for one year. ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting ASU 201409 and ASU 2015-14, including the transition method to be applied, however the standards are not expected to have a significant effect on its condensed consolidated financial statements.

 

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its financial position and results of operations.

 

Reclassifications.  Certain prior period balances in the unaudited condensed consolidated balance sheets and unaudited condensed consolidated statement of operations have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.

 

2.  SEGMENT REPORTING.

 

We conduct our operations within two reportable operating segments. We identified each segment based on management’s responsibility and the nature of their products, services, and costs. There are no major distinctions in geographical areas served as nearly all operations are in the Williston Basin of the United States. The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and natural gas subsidiaries, is responsible for finding and producing oil and natural gas. The Oilfield Services segment, consisting of RockPile and its subsidiaries, is responsible for a variety of oilfield and well completion services for both TUSA-operated wells and wells operated by third-parties. Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments. Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. 

 

12


 

Management evaluates the performance of our segments based upon net income (loss) before income taxes. The following tables present selected financial information for our operating segments for the three months ended April 30, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30, 2016

 

 

Exploration

 

 

 

 

Corporate

 

 

 

 

 

 

 

 

and

 

Oilfield

 

and

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Other

    

Eliminations

    

Total

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

24,852

 

$

 —

 

$

 —

 

$

 —

 

$

24,852

Oilfield services for third parties

 

 

 —

 

 

19,620

 

 

 —

 

 

(100)

 

 

19,520

Intersegment revenues

 

 

 —

 

 

5,696

 

 

 —

 

 

(5,696)

 

 

 —

Total revenues

 

 

24,852

 

 

25,316

 

 

 —

 

 

(5,796)

 

 

44,372

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and production taxes

 

 

10,681

 

 

 —

 

 

 —

 

 

 —

 

 

10,681

Gathering, transportation and processing

 

 

5,608

 

 

 —

 

 

 —

 

 

 —

 

 

5,608

Depreciation and amortization

 

 

9,605

 

 

5,690

 

 

365

 

 

(772)

 

 

14,888

Impairments

 

 

79,000

 

 

 —

 

 

 —

 

 

 —

 

 

79,000

Accretion of asset retirement obligations

 

 

123

 

 

 —

 

 

 —

 

 

 —

 

 

123

Oilfield services

 

 

 —

 

 

20,381

 

 

 —

 

 

(3,710)

 

 

16,671

General and administrative, net of amounts capitalized:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and benefits

 

 

1,649

 

 

3,288

 

 

939

 

 

 —

 

 

5,876

Share-based compensation

 

 

777

 

 

168

 

 

867

 

 

 —

 

 

1,812

Other general and administrative

 

 

388

 

 

1,207

 

 

2,040

 

 

 —

 

 

3,635

Total operating expenses

 

 

107,831

 

 

30,734

 

 

4,211

 

 

(4,482)

 

 

138,294

Income (loss) from operations

 

 

(82,979)

 

 

(5,418)

 

 

(4,211)

 

 

(1,314)

 

 

(93,922)

Other income (expense)

 

 

2,908

 

 

(1,250)

 

 

(1,681)

 

 

(162)

 

 

(185)

Income (loss) before income taxes

 

$

(80,071)

 

$

(6,668)

 

$

(5,892)

 

$

(1,476)

 

$

(94,107)

As of April 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

152,621

 

$

16,763

 

$

28,264

 

$

 —

 

$

197,648

Net oil and natural gas properties

 

$

417,383

 

$

 —

 

$

 —

 

$

(87,055)

 

$

330,328

Oilfield services equipment, net

 

$

 —

 

$

44,147

 

$

 —

 

$

 —

 

$

44,147

Other property and equipment, net

 

$

8,898

 

$

16,681

 

$

14,919

 

$

 —

 

$

40,498

Total assets

 

$

636,562

 

$

105,050

 

$

90,039

 

$

(90,235)

 

$

741,416

Total liabilities

 

$

811,941

 

$

133,045

 

$

156,529

 

$

(3,180)

 

$

1,098,335

 

 

13


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30, 2015

 

 

Exploration

 

 

 

 

Corporate

 

 

 

 

 

 

 

 

and

 

Oilfield

 

and

 

 

 

 

Consolidated

(in thousands)

 

Production

    

Services

    

Other

    

Eliminations

    

Total

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids sales

 

$

47,778

 

$

 —

 

$

 —

 

$

 

 

$

47,778

Oilfield services for third parties

 

 

 —

 

 

71,090

 

 

 —

 

 

(580)

 

 

70,510

Intersegment revenues

 

 

 —

 

 

9,504

 

 

 —

 

 

(9,504)

 

 

 —

Total revenues

 

 

47,778

 

 

80,594

 

 

 —

 

 

(10,084)

 

 

118,288

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and production taxes

 

 

15,710

 

 

 —

 

 

 —

 

 

 —

 

 

15,710

Gathering, transportation and processing

 

 

6,348

 

 

 —

 

 

 —

 

 

 —

 

 

6,348

Depreciation and amortization

 

 

29,285

 

 

9,489

 

 

325

 

 

(1,307)

 

 

37,792

Impairments

 

 

192,000

 

 

 —

 

 

 —

 

 

 —

 

 

192,000

Accretion of asset retirement obligations

 

 

57

 

 

 —

 

 

 —

 

 

 —

 

 

57

Oilfield services

 

 

 —

 

 

70,586

 

 

 —

 

 

(6,360)

 

 

64,226

General and administrative, net of amounts capitalized:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Salaries and benefits

 

 

341

 

 

4,829

 

 

3,253

 

 

 —

 

 

8,423

Share-based compensation

 

 

321

 

 

51

 

 

2,136

 

 

 —

 

 

2,508

Other general and administrative

 

 

407

 

 

1,797

 

 

1,724

 

 

 —

 

 

3,928

Total operating expenses

 

 

244,469

 

 

86,752

 

 

7,438

 

 

(7,667)

 

 

330,992

Income (loss) from operations

 

 

(196,691)

 

 

(6,158)

 

 

(7,438)

 

 

(2,417)

 

 

(212,704)

Other income (expense)

 

 

(21,002)

 

 

(875)

 

 

1,448

 

 

(507)

 

 

(20,936)

Income (loss) before income taxes

 

$

(217,693)

 

$

(7,033)

 

$

(5,990)

 

$

(2,924)

 

$

(233,640)

 

Eliminations and Other. For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs.

 

Under the full cost method of accounting, we defer recognition of oilfield services income (intersegment revenues less cost of oilfield services and related depreciation) for wells that we operate and this deferred income is credited to proved oil and natural gas properties. In addition, we eliminate our non-operating partners’ share of oilfield services income for well completion activities on properties we operate. We also defer Caliber gross profit from our share of its income associated with services it provided that were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties.

 

The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced. For the three months ended April 30, 2015 and 2016, $0.5 million and $0.0 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment.

 

These differences, as well as differing amounts for impairments, result in basis differences between the net oil and gas property amounts presented in Triangle’s financial statements compared to those presented in TUSA’s standalone financial statements.

 

14


 

3.  LONG-TERM DEBT.

 

The Company’s long-term debt consisted of the following as of January 31, 2016 and April 30, 2016:

 

 

 

 

 

 

 

 

 

 

(in thousands)

    

January 31, 2016

    

April 30, 2016

TUSA credit facility due October 2018

 

$

243,772

 

$

347,472

RockPile credit facility due March 2019

 

 

112,000

 

 

112,000

TUSA 6.75% notes due July 2022

 

 

398,419

 

 

372,599

5% convertible note

 

 

142,799

 

 

144,584

Other notes and mortgages payable

 

 

14,065

 

 

13,405

Total principal

 

 

911,055

 

 

990,060

Debt issuance costs

 

 

(7,924)

 

 

(7,299)

Total debt

 

 

903,131

 

 

982,761

Less current portion of debt:

 

 

 

 

 

 

TUSA credit facility

 

 

 —

 

 

(347,472)

RockPile credit facility

 

 

(112,000)

 

 

(112,000)

TUSA 6.75% notes

 

 

 —

 

 

(372,599)

Other notes and mortgages payable

 

 

(2,088)

 

 

(1,573)

Debt issuance costs

 

 

 —

 

 

6,847

Total current portion of long-term debt

 

 

(114,088)

 

 

(826,797)

Total long-term debt

 

$

789,043

 

$

155,964

 

TUSA Credit Facility. On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates. On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million. The TUSA credit facility has a maturity date of October 16, 2018. On April 30, 2015, TUSA entered into Amendment No. 1 to its Second Amended and Restated Credit Agreement (“Amendment No. 1”) to, among other things, replace the existing total funded debt leverage ratio with a senior secured leverage ratio, add an interest coverage ratio, and add an equity cure right for non-compliance with financial covenants.

 

Borrowings under the TUSA credit facility bear interest, at TUSA’s option, at either (i) the adjusted base rate (the highest of (A) the administrative agent’s prime rate, (B) the federal funds rate plus 0.50%, or (C) the one month Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the Eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base.

 

The lenders redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. If the new borrowing base resulting from any regularly scheduled, semi-annual redetermination is less than the amount of outstanding credit exposure under the credit facility, TUSA will be required to (i) pledge additional collateral, (ii) repay the principal amount of the loans in an amount sufficient to eliminate the excess, (iii) repay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii). In contrast, if a borrowing base deficiency results from an unscheduled redetermination, TUSA must immediately repay the excess and may not remedy such deficiency by pledging additional collateral or repaying the excess in installments. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA credit facility. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries. The obligations under the TUSA credit facility are guaranteed by TUSA’s subsidiaries, but Triangle is not a guarantor.

 

On April 28, 2016, the lenders significantly reduced the borrowing base under the credit facility from $350.0 million to $225.0 million, which was a greater reduction than we had anticipated. As of April 30, 2016, TUSA had $347.5 million of outstanding borrowings and $2.5 million of outstanding letters of credit under the credit facility, or $125.0 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). TUSA had cash on hand of approximately $152.3 million at April 30, 2016. TUSA elected to repay the borrowing base deficiency in three equal monthly installments of $41.7 million, the first payment of which was paid on May 31, 2016. Any non-payment of the borrowing base deficiency could result in an event of default.

15


 

 

The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens. In addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current assets to consolidated current liabilities (current ratio), consolidated senior secured debt to consolidated EBITDAX (senior secured leverage ratio), and interest to consolidated EBITDAX (interest coverage ratio).

 

On May 27, 2016, TUSA entered into the TUSA Forbearance Amendment, pursuant to which the lenders agreed to forbear exercising any rights or remedies available to them arising from any breach related to the minimum required current ratio or the senior secured leverage ratio that may have occurred as of April 30, 2016. The forbearance is conditioned upon, among other things, TUSA making the first borrowing base deficiency payment on May 31, 2016, maintaining minimum specified cash balances and agreeing not to prepay, redeem or purchase any other debt prior to its scheduled maturity other than certain refinancings. The forbearance is effective until the earlier of July 8, 2016 or specified forbearance termination events including the commencement of any bankruptcy or reorganization proceeding under applicable bankruptcy or insolvency law.

 

As of April 30, 2016, TUSA was in breach of the minimum current ratio requirement. Although it is difficult to forecast future operations in this low commodity price environment, TUSA may not comply with all of the financial covenants contained in its credit facility in future periods unless those requirements are waived or amended or unless TUSA can obtain new capital or equity cure financing. The greater than expected reduction in the borrowing base contributed to the breach of the minimum current ratio requirement at April 30, 2016, and will have a negative impact on TUSA’s expected financial covenant performance for the remainder of fiscal year 2017 and increase the amount of any needed equity cure. TUSA remains in discussions regarding strategic alternatives, but there are no guarantees these discussions or negotiations will be successful. If TUSA is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, TUSA’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable after the forbearance period ends. If this happens, the Company does not currently have sufficient liquidity to make the TUSA equity cures that we expect may be necessary in the next 12 months, and TUSA does not have sufficient cash on hand to repay this outstanding debt. Therefore, the condensed consolidated balance sheet reflects all of the amounts outstanding under the TUSA credit facility as current liabilities as of April 30, 2016. Triangle has not guaranteed TUSA’s obligations under the credit facility.

 

RockPile Credit Facility. On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility. On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million. The RockPile credit facility has a maturity date of March 25, 2019.

 

Borrowings under the RockPile credit facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter.

 

RockPile pays a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile also pays a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount. The obligations under the RockPile credit facility are guaranteed by RockPile’s subsidiaries, but Triangle is not a guarantor.

 

The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges. RockPile has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle on or before ten days following the date that its compliance certificates are due (45 days after quarter ends and 120 days after its fiscal year end) to cure such a breach (an equity cure). The cure amount is defined as the amount which, if added to EBITDA for the test period in which a default of the financial covenant occurred, would cause the financial covenant for such test period to be satisfied. RockPile may

16


 

exercise this cure right in no more than two of any four consecutive fiscal quarters and no more than five times during the term of the credit facility. To date, RockPile has not exercised an equity cure right.

 

On April 13, 2016, RockPile entered into the RockPile Waiver Amendment, which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 and April 30, 2016. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of the RockPile Waiver Amendment, RockPile is precluded from drawing additional funds absent further amendment of the facility.

 

Beginning with the second quarter and for the remainder of fiscal year 2017, RockPile does not expect to comply with all of the financial covenants contained in its credit facility unless those requirements are also waived or amended or unless RockPile can obtain new capital or equity cure financing. RockPile remains in discussions regarding strategic alternatives, but there are no guarantees these discussions or negotiations will be successful. If RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the RockPile equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the condensed consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016 and April 30, 2016. Triangle has not guaranteed RockPile’s obligations under the credit facility, and there are no cross-default provisions in Triangle’s or TUSA’s other debt agreements that could cause the acceleration of such indebtedness as a result of the RockPile credit facility default.

 

TUSA 6.75% Notes.  On July 18, 2014, TUSA and a wholly-owned subsidiary guarantor entered into an Indenture (the “Indenture”) governing the terms of TUSA’s $450.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (the “TUSA 6.75% Notes”).

 

The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act. The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the initial guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014. The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

 

The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014. Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture. The Company incurred $10.5 million of offering costs which have been deferred and are being recognized using the effective interest method over the life of the notes.

 

TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture. On or after July 15, 2017, TUSA may redeem some or all of the TUSA 6.75% Notes at any time at a price equal to 105.063% of the principal amount of the notes redeemed (103.375% after July 15, 2018, 101.688% after July 15, 2019 and 100% on and after July 15, 2020), plus accrued and unpaid interest, if any, to the redemption date. In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at 106.75% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings and cash contributions to capital stock. If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the repurchase date.

 

The Indenture permits the repurchase of TUSA 6.75% Notes in the open market. During the first quarter of fiscal year 2017, TUSA repurchased TUSA 6.75% Notes with a face value of $17.6 million for $3.2 million, and Triangle repurchased TUSA 6.75% Notes with a face value of $8.2 million for $1.4 million. TUSA immediately retired the TUSA 6.75% Notes repurchased during the first quarter, and Triangle continues to hold the TUSA 6.75% Notes that it repurchased. As a result of the repurchases, the Company recognized a gain on extinguishment of debt of $21.2 million for the quarter ended April 30, 2016.

17


 

 

The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any restricted subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets. These covenants are subject to a number of important exceptions and qualifications.

 

As noted above, if the TUSA credit facility lenders declare any financial covenant breach an event of default, there are cross-default provisions in the Indenture of the TUSA 6.75% Notes that could enable holders of the TUSA 6.75% Notes to declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable and TUSA does not have sufficient cash on hand to repay this outstanding debt. Therefore, the condensed consolidated balance sheet reflects the balance outstanding of the TUSA 6.75% Notes as current liabilities as of April 30, 2016. Triangle has not guaranteed TUSA’s obligations under the TUSA 6.75% Notes.

 

Convertible Note. On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a 5% convertible note with an initial principal amount of $120.0 million (the “Convertible Note”) that became convertible after November 16, 2012, in whole or in part, into the Company’s common stock at a conversion rate of one share per $8.00 of outstanding balance.

 

The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after September 30, 2017, the Company has the option to make such interest payments in cash. As of April 30, 2016, $24.6 million of accrued interest has been added to the principal balance of the Convertible Note.

 

The Convertible Note does not have a stated maturity. Following July 31, 2017, if the trading price of the Company’s common stock exceeds $11.00 per share for 20 consecutive trading days and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following July 31, 2020, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal plus accrued and unpaid interest, payable in cash. Further, following July 31, 2022, a change of control of the Company, or certain other fundamental changes (as defined in the indenture), the holder of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, with an additional make-whole payment for scheduled interest payments remaining if such right is exercised prior to July 31, 2017.

 

If any creditor exercises their right to demand payment, it may reduce the amortization period of related unamortized debt issuance costs.

 

 

4.  HEDGING AND COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS.

 

Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price, and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure or reduce existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

 

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with six counterparties. The Company has netting arrangements with each counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

 

18


 

The Company’s commodity derivative instruments are measured at fair value. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments. The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows. 

 

The components of commodity derivative gains (losses) in the condensed consolidated statements of operations are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

 

2015

 

2016

Realized commodity derivative gains (losses)

 

$

19,468

 

$

2,104

Unrealized commodity derivative gains (losses)

 

 

(33,442)

 

 

(11,785)

Commodity derivative gains (losses), net

 

$

(13,974)

 

$

(9,681)

 

The Company’s commodity derivative contracts as of April 30, 2016 are summarized below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted

 

Weighted

 

Weighted

 

 

Contract

 

 

 

Quantity

 

Average

 

Average

 

Average

 

    

Type

    

Basis (1)

    

(Bbl/d)

 

Put Strike

 

Call Strike

  

Price

May 1, 2016 to January 31, 2017

 

Swap

 

NYMEX

 

2,558

 

 

n/a

 

 

n/a

 

$

55.64

February 1, 2017 to January 31, 2018

 

Swap

 

NYMEX

 

2,745

 

 

n/a

 

 

n/a

 

$

53.36

(1)

“NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

 

The estimated fair values of commodity derivatives included in the condensed consolidated balance sheets at January 31, 2016 and April 30, 2016 are summarized below. The Company does not offset asset and liability positions with the same counterparties within the condensed consolidated financial statements; rather, all contracts are presented at their gross estimated fair value.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

January 31, 2016

 

April 30, 2016

Current Assets:

 

 

 

 

 

 

Crude oil derivative contracts

 

$

12,370

 

$

6,681

Other Long-Term Assets:

 

 

 

 

 

 

Crude oil derivative contracts

 

 

9,012

 

 

2,916

Total derivative asset

 

$

21,382

 

$

9,597

 

 

5.  EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES.

 

Equity Investment. The following summarizes the activities related to the Company’s equity investment in Caliber for the three months ended April 30, 2016:

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

 

2016

Balance at beginning of year

 

$

45,600

Capital contributions

 

 

 —

Distributions

 

 

 —

Equity investment share of net income before intra-company profit eliminations

 

 

100

Change in fair value of warrants

 

 

 —

Other than temporary impairment

 

 

 —

Balance at end of year

 

$

45,700

Fair value of trigger unit warrants and warrants at April 30, 2016

 

$

3,600

 

Equity Investment Derivatives. At January 31, 2016 and April 30, 2016, the Company held Class A (Series 1 through Series 4 and Series 6) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity

19


 

investment derivatives and are valued at each reporting period using valuation techniques for which the inputs are generally less observable than from objective sources.

 

6.  CAPITAL STOCK.

 

At April 30, 2016, the Company had 106.5 million shares of common stock issued or reserved for issuance and 76.3 million shares of common stock issued and outstanding. The Company also had 0.9 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan, 6.0 million shares of common stock reserved for issuance under its CEO Stand-Alone Stock Option Agreement, 1.6 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the “2014 Plan”), and 3.6 million shares of reserved common stock that remained available for issuance under the 2014 Plan. Lastly, the Company had 18.1 million shares of common stock reserved for issuance pursuant to the Convertible Note.

 

The Company’s Board of Directors (the “Board”) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares of common stock potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. There were no common stock repurchases for the three months ended April 30, 2016. As of April 30, 2016, the number of shares of common stock remaining available for repurchase under the Board approved program was 6,033,290 shares.

 

7.  SHARE-BASED COMPENSATION.

 

The Company has granted equity awards to officers, directors, and certain employees of the Company including restricted stock units and stock options. In addition, RockPile has granted Series B Units which represent interests in future RockPile profits. The Company measures its awards based on the award’s grant date fair value which is recognized on a straight-line basis over the applicable vesting period.

 

On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014. No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions. The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and consultants of the Company and its subsidiaries. The maximum number of shares of common stock issuable under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

 

For the three months ended April 30, 2015 and 2016, the Company recorded share-based compensation as follows:

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

    

2015

    

2016

Restricted stock units

 

$

2,079

 

$

830

Stock options

 

 

698

 

 

1,034

RockPile Series B Units

 

 

51

 

 

168

 

 

 

2,828

 

 

2,032

Less amounts capitalized to oil and natural gas properties

 

 

(320)

 

 

(220)

Compensation expense

 

$

2,508

 

$

1,812

 

Restricted Stock Units.  As of April 30, 2016 there was approximately $10.0 million of total unrecognized compensation expense related to unvested restricted stock units. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 1.9 years on a weighted average basis. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit.

 

20


 

The following table summarizes the activity for our restricted stock units during the three months ended April 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average

 

 

Number of

 

Award Date

 

    

Shares

    

Fair Value

Restricted stock units outstanding - January 31, 2016

 

3,455,845

 

$

6.35

Units granted

 

 —

 

$

 —

Units forfeited

 

(444,254)

 

$

8.63

Units vested

 

(708,762)

 

$

5.54

Restricted stock units outstanding - April 30, 2016

 

2,302,829

 

$

6.16

 

Stock Options. The following table summarizes the activity for our stock options during the three months ended April 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted 

 

 

Number of

 

Average

 

    

Shares

    

Exercise Price

Options outstanding - January 31, 2016 (1,433,334 exercisable)

 

6,700,000

 

$

11.54

Options forfeited

 

(466,666)

 

$

14.00

Options exercised

 

 —

 

$

 —

Options granted

 

 —

 

$

 —

Options outstanding - April 30, 2016 (1,433,334 exercisable)

 

6,233,334

 

$

11.35

 

The following table summarizes the stock options outstanding at April 30, 2016:  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Remaining

 

 

 

 

 

 

Exercise Price

 

Contractual Life

 

Number of Shares

per Share

    

(years)

    

Outstanding

    

Exercisable

$

7.50

 

7.18

 

 

750,000

 

 

150,000

$

8.50

 

7.18

 

 

750,000

 

 

150,000

$

10.00

 

7.18

 

 

1,500,000

 

 

300,000

$

12.00

 

7.18

 

 

1,500,000

 

 

300,000

$

15.00

 

7.18

 

 

1,500,000

 

 

300,000

$

12.00

 

5.36

 

 

77,778

 

 

77,778

$

14.00

 

5.36

 

 

77,778

 

 

77,778

$

16.00

 

8.37

 

 

77,778

 

 

77,778

 

 

 

 

 

 

6,233,334

 

 

1,433,334

 

 

 

 

 

 

 

 

 

 

Weighted average exercise price per share

$

11.35

 

$

11.70

 

 

 

 

 

 

 

 

 

 

Weighted average remaining contractual life

 

7.15

 

 

7.05

 

As of April 30, 2016 there was approximately $8.0 million of total unrecognized compensation expense related to stock options. This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 2.2 years.

 

RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units, which are voting units with an 8% preference, and Series B Units, which are non-voting equity awards that generally vest over a requisite service period of 3 to 5 years. RockPile approved a plan that includes provisions allowing RockPile to make equity grants in the form of restricted units (“Series B Units”) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units.

 

21


 

The following table summarizes the activity for RockPile’s Series B Units for the three months ended April 30,  2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series

 

Series

 

Series

 

Series

 

Series

 

Series

 

 

 

    

B-1 units

    

B-2 units

    

B-3 units

    

B-4 units

    

B-5 units

    

B-6 units

    

Total

Units outstanding - January 31, 2016

 

2,920,000

 

60,000

 

814,000

 

1,321,200

 

397,500

 

217,500

 

5,730,200

Units redeemed

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Units granted

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Units forfeited

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Units outstanding - April 30, 2016

 

2,920,000

 

60,000

 

814,000

 

1,321,200

 

397,500

 

217,500

 

5,730,200

Vested

 

2,920,000

 

60,000

 

352,000

 

117,600

 

 —

 

 —

 

3,449,600

Unvested

 

 —

 

 —

 

462,000

 

1,203,600

 

397,500

 

217,500

 

2,280,600

 

Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period. As of April 30, 2016, there was approximately $1.7 million of unrecognized compensation expense related to unvested Series B Units. We expect to recognize such expense on a pro-rata basis on the Series B Units’ over the remaining vesting period of the related awards of 2.6 years.

 

8.  FAIR VALUE MEASUREMENTS.

 

The FASB’s ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

 

·

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

·

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and

·

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations.

 

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2016 and April 30, 2016, by level within the fair value hierarchy:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of January 31, 2016

(in thousands)

    

Level 1

    

Level 2

    

Level 3

    

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative assets

 

$

 —

 

$

21,382

 

$

 —

 

$

21,382

Equity investment derivative assets

 

$

 —

 

$

 —

 

$

3,600

 

$

3,600

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative liabilities

 

$

 —

 

$

 —

 

$

 —

 

$

 —

RockPile earn-out liability

 

$

 —

 

$

(1,265)

 

$

 —

 

$

(1,265)

 

22


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of April 30, 2016

(in thousands)

    

Level 1

    

Level 2

    

Level 3

    

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative assets

 

$

 —

 

$

9,597

 

$

 —

 

$

9,597

Equity investment derivative assets

 

$

 —

 

$

 —

 

$

3,600

 

$

3,600

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

RockPile earn-out liability

 

$

 —

 

$

(586)

 

$

 —

 

$

(586)

 

Commodity Derivative Instruments. The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company’s own credit rating. In considering counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At April 30, 2016, commodity derivative instruments utilized by the Company consisted of swaps. The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange. As such, the Company has classified these commodity derivative instruments as Level 2.

 

Caliber Class A Warrants (Series 1 through Series 4 and Series 6). The Company determines its estimate of the fair value of Caliber Class A Warrants using a Monte Carlo Simulation (“MCS”) model. For each MCS, the values of the Class A Units and Class A Warrants were forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly. At April 30, 2016, the fair values of the underlying Class A Units and Class A Warrants were estimated employing an income approach using a MCS model and discounted cash flows, and a market approach based on observed valuation multiples for comparable public companies. Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, the Company has classified these instruments as Level 3.

 

Earn-out Liability. The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well Service, Inc. using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2.

 

Fair Value of Financial Instruments.  The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A Warrants (discussed above), and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable. The fair values of the other notes and mortgages payable is not significantly different than their carrying values. The fair value of the TUSA 6.75% Notes is derived from quoted market prices (Level 1). The Convertible Note’s estimated fair value is based on quoted market prices for similar debt instruments and option pricing (Level 3). This disclosure does not impact our financial position, results of operations or cash flows.

 

The carrying values and fair values of the Company’s debt instruments are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 31, 2016

 

April 30, 2016

 

 

Carrying

 

Estimated

 

Carrying

 

Estimated

(in thousands)

    

Value

    

Fair Value

    

Value

    

Fair Value

TUSA credit facility

 

$

243,772

 

$

243,772

 

$

347,472

 

$

347,472

RockPile credit facility

 

 

112,000

 

 

(A)

 

 

112,000

 

 

(A)

TUSA 6.75% notes

 

 

398,419

 

 

71,051

 

 

372,599

 

 

(A)

5% convertible note

 

 

142,799

 

 

22,564

 

 

144,584

 

 

(A)

Other notes and mortgages payable

 

 

14,065

 

 

14,065

 

 

13,405

 

 

13,405

(A)As described further in Notes 1 and 3, TUSA and RockPile are or are expected to be in breach of certain financial covenants and the Company has engaged professional advisors to advise it in restructuring certain debt instruments.

23


 

Therefore, the Company is unable to reasonably determine the fair value for these financial instruments due to a lack of actively quoted market prices and uncertainties related to these restructuring activities.

 

9.  RELATED PARTY TRANSACTIONS.

 

TUSA and an affiliate of Caliber have entered into certain midstream services agreements for (i) crude oil gathering, stabilization, treating and redelivery; (ii) natural gas compression, gathering, dehydration, processing and redelivery; (iii) produced water transportation and disposal services; and (iv) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. The agreements also include an acreage dedication from TUSA and a firm volume commitment by the Caliber affiliate for each service line. TUSA has agreed to deliver minimum monthly revenues derived from the fees paid by TUSA to the Caliber affiliate for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning in 2014. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $293.7 million was outstanding at April 30, 2016. The agreements permit TUSA to build up credits against future monthly commitments for the excess of actual monthly revenues over the minimum monthly revenues. As of April 30, 2016, TUSA has built up a cumulative credit of $41.5 million. Credits may be carried forward for a period of four years from the date of the accrual. TUSA is required to pay Caliber for any deficiency of actual monthly revenues if no credits are available.

 

TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement that will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years from the in-service date in March 2015. The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water.

 

TUSA had payables to Caliber of $14.6 million and $19.5 million at January 31, 2016 and April 30, 2016, respectively.

 

10.  CONTINGENCIES.

 

On May 26, 2016, the Company received a demand for arbitration in connection with an exploration and development agreement entered into in August 2011 with a third party operator. The demand alleges damages in connection with non-payment of a promote fee established under the agreement for 10% of the cost of drilling wells in which the Company participated that were drilled in an area of mutual interest. The Company is assessing the merits of the claim but does not anticipate that it will have a material effect on its consolidated financial position, results of operations or liquidity.

 

In addition, the Company is a party from time to time to other claims and legal actions that arise in the ordinary course of business. The Company believes that the ultimate impact, if any, of these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity.

 

11.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

 

 

2015

    

2016

Cash paid during the period for:

 

 

 

 

 

 

Interest expense

 

$

1,890

 

$

15,674

Income taxes

 

$

 —

 

$

 —

 

 

 

 

 

 

 

Non-cash investing activities:

 

 

 

 

 

 

Additions (reductions) to oil and natural gas properties through:

 

 

 

 

 

 

Increase (decrease) in accounts payable and accrued liabilities

 

$

(7,932)

 

$

(67)

Capitalized stock based compensation

 

$

320

 

$

220

Change in asset retirement obligations

 

$

242

 

$

 —

 

 

24


 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

 

Overview

 

We are an independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services. We conduct these activities primarily in the Williston Basin of North Dakota and Montana through TUSA and RockPile, the Company’s two principal wholly-owned subsidiaries, and Caliber, our equity joint venture. RockPile also conducts operations in the Permian Basin of Texas.

 

Summary of results for the quarter ended April 30, 2016

 

·

Average daily production volumes were 10,478 Boe/day for the three months ended April 30, 2016, compared to 13,775 Boe/day for the three months ended April 30, 2015, a decrease of 24%.

·

Lower average realized prices of $26.35 per Boe for the three months ended April 30, 2016, versus $38.97 per Boe for the three months ended April 30, 2015, resulted in oil, natural gas and natural gas liquids sales for the three months ended April 30, 2016 of $24.9 million compared to $47.8 million for the three months ended April 30, 2015.

·

TUSA did not drill any wells during the three months ended April 30, 2016.

·

TUSA completed 4 gross (3.5 net) operated wells during the three months ended April 30, 2016. As of April 30, 2016, TUSA had 10 gross (9.6 net) operated wells that have been drilled and were pending completion.

·

RockPile completed 4 TUSA operated wells and 24 third-party wells in the three months ended April 30, 2016, compared to 5 TUSA operated wells and 50 third-party wells in the three months April 30, 2015.

·

Oilfield services revenue for the three months ended April 30, 2016 was $19.5 million compared to $70.5 million for the three months ended April 30, 2015.

·

The competitive oilfield services pricing environment resulted in a negative gross profit of $2.1 million for the three months ended April 30, 2016, compared to a negative gross profit of $2.4 million for the three months ended April 30, 2015 after eliminations of intercompany gross profit.

·

The carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation at April 30, 2016, resulting in an impairment of $79.0 million for the three months ended April 30, 2016.

·

Cash flows used in operating activities were $6.1 million for the three months ended April 30, 2016, compared to cash flows provided by operating activities of $39.3 million for the three months ended April 30, 2015.

 

Liquidity and Ability to Continue as a Going Concern

 

Our unaudited condensed consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. As such, the accompanying unaudited condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. See Item 1. Condensed Consolidated Financial Statements (Unaudited) – Note 1 for further discussion.

 

25


 

Costs Incurred and Capitalized Costs

 

The table below presents costs incurred in oil and natural gas acquisition, exploration, and development activities during the three months ended April 30, 2015 and 2016.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

    

2015

 

2016

Costs incurred during the period

 

 

 

 

 

 

Acquisition of properties:

 

 

 

 

 

 

Proved

 

$

222

 

$

 —

Unproved

 

 

 —

 

 

157

Exploration

 

 

33,375

 

 

6,923

Development

 

 

33,527

 

 

5,571

Oil and natural gas expenditures

 

 

67,124

 

 

12,651

Asset retirement obligations, net

 

 

242

 

 

 —

 

 

$

67,366

 

$

12,651

 

Developed and Undeveloped Acreage

 

As of April 30, 2016, we have under lease approximately 218,211 gross and 94,219 net acres in the Williston Basin, with approximately 192,376 gross and 76,285 net acres in our core focus area located predominantly in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of April 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed Acres

 

Undeveloped Acres

 

Total Acres

 

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

North Dakota

 

162,394

 

62,399

 

18,207

 

5,541

 

180,601

 

67,940

Montana

 

8,272

 

6,190

 

29,338

 

20,089

 

37,610

 

26,279

Total Williston Basin

 

170,666

 

68,589

 

47,545

 

25,630

 

218,211

 

94,219

26


 

Summary of Operating Results

 

The following table reflects the components of our production volumes, average realized prices, oil, natural gas and natural gas liquids revenues, and operating expenses for the periods indicated. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. The information set forth below is not necessarily indicative of future results.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

Oil and Natural Gas Operations

    

2015

 

2016

Production volumes:

 

 

 

 

 

 

Crude oil (Mbbls)

 

 

1,025

 

 

713

Natural gas (MMcf)

 

 

739

 

 

794

Natural gas liquids (Mbbls)

 

 

78

 

 

98

Total barrels of oil equivalent (Mboe)

 

 

1,226

 

 

943

 

 

 

 

 

 

 

Average daily production volumes (Boe/d)

 

 

13,775

 

 

10,478

 

 

 

 

 

 

 

Average realized prices:

 

 

 

 

 

 

Crude oil ($ per Bbl)

 

$

43.36

 

$

32.22

Natural gas ($ per Mcf)

 

$

3.23

 

$

1.97

Natural gas liquids ($ per Bbl)

 

$

12.18

 

$

3.19

Total average realized price ($ per Boe)

 

$

38.97

 

$

26.35

 

 

 

 

 

 

 

Oil, natural gas and natural gas liquids revenues (in thousands):

 

 

 

 

 

 

Crude oil

 

$

44,442

 

$

22,973

Natural gas

 

 

2,386

 

 

1,566

Natural gas liquids

 

 

950

 

 

313

Total oil, natural gas and natural gas liquids revenues

 

$

47,778

 

$

24,852

 

 

 

 

 

 

 

Operating expenses (in thousands):

 

 

 

 

 

 

Lease operating expenses

 

$

10,923

 

$

8,602

Gathering, transportation and processing

 

 

6,348

 

 

5,608

Production taxes

 

 

4,787

 

 

2,079

Oil and natural gas amortization expense

 

 

28,679

 

 

9,455

Impairment of oil and natural gas properties

 

 

192,000

 

 

79,000

Accretion of asset retirement obligations

 

 

57

 

 

123

Total operating expenses

 

$

242,794

 

$

104,867

 

 

 

 

 

 

 

Operating expenses per Boe:

 

 

 

 

 

 

Lease operating expenses

 

$

8.91

 

$

9.12

Gathering, transportation and processing

 

$

5.18

 

$

5.95

Production taxes

 

$

3.90

 

$

2.20

Oil and natural gas amortization expense

 

$

23.39

 

$

10.03

 

Comparison of the Quarter Ended April 30, 2016 to the Quarter Ended April 30, 2015

 

Oil, Natural Gas and Natural Gas Liquids Revenues. Revenues from oil, natural gas and natural gas liquids for the three months ended April 30, 2016 decreased 48% to $24.9 million from $47.8 million for the three months ended April 30, 2015. Total production decreased 24% due to the suspension of our drilling program, wells shut-in for workovers, and natural production declines. This decrease in production was accompanied by a 32% decrease in weighted average realized prices from $38.97 per Boe for the three months ended April 30, 2015 to $26.35 per Boe for the three months ended April 30, 2016.

 

Lease Operating Expenses.  Lease operating expenses of $9.12 per Boe for the three months ended April 30, 2016 were comparable to $8.91 per Boe for the three months ended April 30, 2015. We expect that lease operating expenses on a per Boe basis in fiscal year 2017 will continue to be similar to those incurred in fiscal year 2016.

 

27


 

Gathering, Transportation and Processing.  Gathering, transportation and processing expenses increased to $5.95 per Boe for the three months ended April 30, 2016, compared to $5.18 per Boe for the three months ended April 30, 2015. We began transporting and processing our oil, natural gas, and natural gas liquids through Caliber’s facilities in fiscal year 2015. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and processing expenses. We expect future expenses on a per Boe basis will be similar to those incurred in the first quarter of fiscal year 2017.

 

Production Taxes. Production taxes decreased 57% in the first quarter of fiscal year 2017 to $2.1 million from $4.8 million for the first quarter of fiscal year 2016. The 48% decrease in oil, natural gas and natural gas liquids revenues for the three months ended April 30, 2016 versus the three months ended April 30, 2015 is the primary reason for the decrease.

 

Oil and Natural Gas Amortization. Oil and natural gas amortization expense decreased 67% to $9.5 million for the three months ended April 30, 2016 from $28.7 million for the three months ended April 30, 2015. On a per Boe basis, our oil and natural gas amortization expense decreased by $13.36 from $23.39 for the three months ended April 30, 2015 to $10.03 for the three months ended April 30, 2016 primarily due to the impairments recorded in fiscal year 2016.

 

Impairment of Oil and Natural Gas Properties. During the first quarters of fiscal years 2016 and 2017, we recorded non-cash impairments of $192.0 million and $79.0 million, respectively, to the carrying value of our proved oil and natural gas properties as a result of the effects of significant declines in oil, natural gas and natural gas liquids prices on the ceiling test limitation. The trailing twelve month reference prices at April 30, 2016 were $45.16 per Bbl of oil, $2.33 per MMbtu for natural gas and $23.10 per Bbl of natural gas liquids.

 

Because the ceiling calculation requires rolling 12-month average commodity prices, the effect of lower quarter over- quarter prices in fiscal year 2017 compared to fiscal year 2016 will be a lower ceiling limitation each quarter. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further. The amount of any future impairment is difficult to predict and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

 

If the simple average of oil, natural gas and natural gas liquids prices as of the first day of each month for the trailing 12-month period ended April 30, 2016 had been $42.38 per Bbl of oil, $2.20 per MMbtu for natural gas and $22.83 per Bbl of natural gas liquids and all other factors remained constant, our impairment for the three months ended April 30, 2016 would have increased, on a pro forma basis, by approximately $47.0 million. The aforementioned prices were calculated based on a twelve-month simple average, which includes the first day of the month oil and natural gas spot prices through June 1, 2016 and first of the month forward strip prices for July 1, 2016 based on forward strip prices as of June 1, 2016.

 

This calculation of the impact of lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil, natural gas and natural gas liquids prices. Therefore, this calculation strictly isolates the impact of commodity prices on our ceiling test limitation and proved reserves. The impact of price is only a single variable in the estimation of our proved reserves and other factors could have a significant impact on future reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, changes in costs, drilling results, revisions due to performance and other factors, changes in development plans and production. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

 

The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and natural gas properties is not reversible at a later date.

 

Oilfield Services Gross Profit. We formed RockPile with the strategic objective of having both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to TUSA and other operators in the Williston Basin. Since formation, RockPile has been focused on procuring new oilfield and complementary well completion equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers. In addition, RockPile is currently providing oilfield services in the Permian Basin of Texas and evaluating opportunities in other areas. RockPile’s results of operations are affected by a

28


 

number of variables including drilling and stimulation activity, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistics expenses, insurance, repairs and maintenance, and safety costs. Cost of goods sold as a percentage of revenue will vary based upon the pricing environment, completion design and equipment utilization. 

 

The table below summarizes the RockPile contribution to our consolidated results for the three months ended April 30, 2015 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30, 2015

 

For the Three Months Ended April 30, 2016

(in thousands)

    

Oilfield Services

    

Eliminations

    

Consolidated

 

Oilfield Services

    

Eliminations

    

Consolidated

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oilfield services

 

$

80,594

 

$

(10,084)

 

$

70,510

 

$

25,316

 

$

(5,796)

 

$

19,520

Total revenues

 

 

80,594

 

 

(10,084)

 

 

70,510

 

 

25,316

 

 

(5,796)

 

 

19,520

Cost of sales

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oilfield services

 

 

70,586

 

 

(6,360)

 

 

64,226

 

 

20,381

 

 

(3,710)

 

 

16,671

Depreciation

 

 

9,489

 

 

(830)

 

 

8,659

 

 

5,690

 

 

(772)

 

 

4,918

Total cost of sales

 

 

80,075

 

 

(7,190)

 

 

72,885

 

 

26,071

 

 

(4,482)

 

 

21,589

Gross profit

 

$

519

 

$

(2,894)

 

$

(2,375)

 

$

(755)

 

$

(1,314)

 

$

(2,069)

 

For the three months ended April 30, 2016, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 18 third-party customers. RockPile has increased its base of third-party customers; however, the competitive oilfield services pricing environment resulted in a 72% decrease in consolidated oilfield services revenues from $70.5 million for the three months ended April 30, 2015 to $19.5 million for the three months ended April 30, 2016. Hydraulic fracturing services resulted in 28 total well completions (4 for TUSA and 24 for third-parties) for the three months ended April 30, 2016, compared to 55 well completions (5 for TUSA and 50 for third parties) for the three months ended April 30, 2015.

 

The current competitive oilfield services pricing environment resulted in a negative gross profit of $2.4 million for the three months ended April 30, 2015, compared to a negative gross profit of $2.1 million for the three months ended April 30, 2016, after eliminations of $2.9 million and $1.3 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very challenging as long as oil and natural gas prices remain near current levels, resulting in continued compressed profit levels.

 

General and Administrative Expenses. The following table summarizes general and administrative expenses for the three months ended April 30, 2015 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30, 2015

 

For the Three Months Ended April 30, 2016

 

 

Exploration

 

 

 

 

 

 

 

 

Exploration

 

 

 

 

 

 

 

 

 

and

 

Oilfield

 

 

 

 

Consolidated

 

and

 

Oilfield 

 

 

 

 

Consolidated

(in thousands)

    

Production

    

Services

    

Corporate

    

Total

    

Production

    

Services

    

Corporate

    

Total

Salaries and benefits

 

$

341

 

$

4,829

 

$

3,253

 

$

8,423

 

$

1,649

 

$

3,288

 

$

939

 

$

5,876

Share-based compensation

 

 

321

 

 

51

 

 

2,136

 

 

2,508

 

 

777

 

 

168

 

 

867

 

 

1,812

Other general and administrative

 

 

407

 

 

1,797

 

 

1,724

 

 

3,928

 

 

388

 

 

1,207

 

 

2,040

 

 

3,635

Total

 

$

1,069

 

$

6,677

 

$

7,113

 

$

14,859

 

$

2,814

 

$

4,663

 

$

3,846

 

$

11,323

 

Total general and administrative expenses decreased $3.6 million to $11.3 million for the three months ended April 30, 2016, compared to $14.9 million for the three months ended April 30, 2015. The decrease in total general and administrative expenses is a result of lower salaries and benefits from staffing reductions and lower share-based compensation costs. Total other general and administrative expenses decreased slightly from $3.9 million for the three months ended April 30, 2015 to $3.6 million for the three months ended April 30, 2016. Restructuring advisory fees incurred of $2.5 million during the three months ended April 30, 2016 were partly offset by a benefit of $1.8 million related to the settlement of contracts. Except for restructuring related expenses and retention compensation, we expect that our fiscal year 2017 general and administrative expenses will continue to be less than fiscal year 2016 due to the reductions in force and other cost reduction measures made in fiscal year 2016.

29


 

 

Commodity Derivatives. We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. During the three months ended April 30, 2015 and 2016, we recognized losses of $14.0 million and $9.7 million, respectively, on our commodity derivative positions due to increases in underlying crude oil prices. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. We recorded a realized commodity derivative gain of $2.1 million in the first quarter of fiscal year 2017, as compared to a realized commodity derivative gain of $19.5 million in the first quarter fiscal year 2016.

 

Income (Loss) from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized no gain or loss on its equity investment derivatives in the first quarters of fiscal years 2016 and 2017, respectively. During the three months ended April 30, 2016, the Company recognized $0.1 million for its share of Caliber’s net income for the period. This income was offset by $0.1 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.0 million. During the three months ended April 30, 2015, the Company recognized $0.4 million for its share of Caliber’s net income for the period. This income was offset by $0.2 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.2 million.

 

Interest Expense. The $10.8 million in interest expense for the three months ended April 30, 2016 consists of (i) $2.0 million in interest related to the TUSA credit facility, (ii) $1.2 million in interest expense associated with RockPile’s credit facility and notes payable, (iii) $6.4 million in interest related to the TUSA 6.75% Notes, (iv) $1.8 million in accrued interest related to the Convertible Note, and (v) $0.1 million in interest expense related to our other debt, all net of $0.7 million of capitalized interest which generally relates to the carrying costs on our unproved properties. We paid $16.4 million of interest expense and capitalized interest in cash.

 

The $9.1 million in interest expense for the three months ended April 30, 2015 consists of (i) $0.9 million in interest related to the TUSA credit facility, (ii) $0.8 million in interest expense associated with RockPile’s credit facility and notes payable (iii) $7.3 million in interest related to the TUSA 6.75% Notes, (iv) $1.7 million in accrued interest related to our Convertible Note, and (v) $0.1 million in interest expense related to our other debt, all net of $1.7 million of capitalized interest. We paid $2.2 million of interest expense and capitalized interest in cash.

 

Income Taxes. We recorded a full valuation allowance against our net deferred tax assets in the first quarter of fiscal year 2016, and we recognized a benefit of $53.4 million compared to no benefit or expense in the first quarter of fiscal year 2017.

 

The carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in impairments of $779.0 million for the year ended January 31, 2016. These impairments resulted in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $286.0 million at January 31, 2016. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

 

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

 

30


 

As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense or for state income taxes.

 

Liquidity and Capital Resources

 

Our liquidity is highly dependent on the prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and are historically volatile. Prices received for production heavily influence our revenue, cash flows, profitability, access to capital and future rate of growth. In addition, commodity prices received by exploration and production companies in the Williston Basin affect the level of drilling activity there, and therefore affect the demand for services provided by RockPile and Caliber.

 

In the first quarter of fiscal year 2017, our average realized price for oil was $32.22 per barrel, a decrease of 26% compared to the average realized price for the first quarter of fiscal year 2016. This reflected the dramatic decrease in the price of oil that has persisted since the second half of fiscal year 2015. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We seek to manage the impact that volatility in commodity prices has on our liquidity by periodically hedging a portion of our oil production to mitigate our potential exposure to price declines and maintaining flexibility in our capital investment program. However, our commodity derivative contracts entered into prior to the aforementioned dramatic decrease in the price of oil expired by December 31, 2015. Although we have entered into additional commodity derivative contracts for oil production in fiscal years 2017 and 2018, those contracts were entered into during the depressed commodity pricing environment, and we will be exposed to continued volatility in crude oil market prices, whether favorable or unfavorable.

 

Although the Company is continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations, continued low commodity prices are expected to result in significantly lower levels of cash flows from operating activities in the future and have limited the Company’s ability to access capital markets. As a result of these and other factors, there is substantial doubt about the Company’s ability to continue as a going concern.

 

As of April 30, 2016, we had approximately $990.1 million of debt outstanding, consisting of $347.5 million for the TUSA credit facility, $112.0 million for the RockPile credit facility, $372.6 million for the TUSA 6.75% Notes, $144.6 million for the Convertible Note, and $13.4 million for other notes and mortgages.

 

As of April 30, 2016, we had cash of $197.6 million consisting primarily of cash held in bank accounts, as compared to $115.8 million at January 31, 2016. At April 30, 2016, we had no available borrowing capacity under the TUSA credit facility or the RockPile credit facility.

 

Cash Flows

 

The following is a summary of our changes in cash and cash equivalents for the three months ended April 30, 2015 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended April 30,

(in thousands)

    

2015

    

2016

Net cash provided by (used in) operating activities

 

$

39,255

 

$

(6,057)

Net cash used in investing activities

 

 

(76,606)

 

 

(10,124)

Net cash provided by financing activities

 

 

19,757

 

 

98,060

Net increase (decrease) in cash and equivalents

 

$

(17,594)

 

$

81,879

 

Net Cash Provided by (Used in) Operating Activities. Cash flows provided by operating activities were $39.3 million for the three months ended April 30, 2015, compared to cash flows used in operating activities of $6.1 million for the three months ended April 30, 2016. Cash flows from operating activities were unfavorably impacted in the three months ended April 30, 2016 by lower realized oil prices and the competitive oilfield services pricing environment compared to the three months ended April 30, 2015.

 

Net Cash Used in Investing Activities. During the three months ended April 30, 2015, we used $76.6 million in cash in investing activities compared to $10.1 million during the three months ended April 30, 2016. During the three months ended April 30, 2015 and 2016, we used $74.8 million and $11.0 million, respectively, on oil and natural gas property expenditures. During the three months ended April 30, 2015 and 2016, we also spent $5.3 million and $0.5 million,

31


 

respectively, on purchases of oilfield services equipment and $2.3 million and $0.0 million, respectively, on other property and equipment, primarily consisting of facility construction and improvements. During the three months ended April 30, 2015, we received net proceeds of $6.0 million from the sale of a salt water disposal well.

 

Net Cash Provided by Financing Activities. Cash flows provided by financing activities for the three months ended April 30, 2015 totaled $19.8 million, as compared to $98.1 million for the three months ended April 30, 2016. Our primary financing activities consisted of net borrowings from our credit facilities of $21.1 million during the three months ended April 30, 2015 and $103.7 million during the three months ended April 30, 2016. In the first quarter of fiscal year 2017, we used cash of $4.6 million to repurchase TUSA 6.75% Notes with a face value of $25.8 million.

 

Capital Requirements Outlook

 

Our cash flows from operations for fiscal year 2016 and the first three months of fiscal year 2017 were insufficient to cover our capital requirements, and we continued to rely on external financing activities. We believe that the lag time between initial investment and cash flows from such investment is typical of the oil and natural gas industry where upfront costs are significant and cash flows are delayed. This holds true across all of our businesses, including drilling and completion costs for TUSA and equipment costs for RockPile. While we are not obligated to fund any further equity commitment for Caliber, the lag time between investment in operations and cash flows is exacerbated in the midstream space where initial construction costs and project timelines are substantial. In a higher oil and natural gas pricing environment such as we experienced in recent years, we expect that our cash flows from operations would increase significantly as additional TUSA oil and natural gas wells commence production, RockPile’s oilfield services increase, and Caliber’s gathering and processing system becomes more fully utilized. However, we expect that current depressed oil and natural gas prices, which have temporarily deferred our drilling program and created a very challenging oilfield services market, will continue to limit our cash flows from operations in upcoming quarters.

 

In response to the current oil and natural gas pricing environment, we have significantly reduced capital expenditures and implemented reductions in force across our businesses, and we may further adjust such expenditures as market dynamics warrant. For fiscal year 2017, TUSA’s capital expenditure plan is focused primarily on completing wells that have been drilled and are awaiting completion, but the number and timing of such completions is dependent upon prevailing oil and natural gas prices. We also anticipate drilling and completing four wells in the second fiscal quarter, and we expect that those will be the only wells we drill in fiscal year 2017 absent a substantial increase in commodity prices.  While we work toward cash flow neutrality in fiscal year 2017, low commodity prices may make it difficult for us to achieve this objective. As a result, we will be primarily dependent on cash on hand as we currently have no further availability under our TUSA and RockPile credit facilities. Any additional liquidity shortfall may be financed through additional debt or equity instruments, if we are able to access the capital markets on acceptable terms, which is highly uncertain. There can be no assurance, however, that we will achieve our anticipated future cash flows from operations, that credit will be available when needed, or that we would be able to complete alternative transactions in the capital markets if needed.

 

If our existing and potential sources of liquidity are not sufficient to allow us to satisfy our commitments and to undertake our planned expenditures, particularly if commodity prices remain depressed for an extended period of time, we have the flexibility to further alter our development program or divest assets. Our operatorship of much of our acreage allows us the ability to adjust our drilling and completion schedules in response to changes in commodity prices or the oilfield services environment. If we are not successful in achieving cash flow neutrality or obtaining sufficient funding on a timely basis on terms acceptable to us, we may be required to curtail our planned expenditures and/or restructure our operations, which may reduce anticipated future cash flows from operations. We are evaluating a variety of strategic alternatives, and we may be required to pursue alternative measures, such as selling material assets or business segments; seeking additional financing; or refinancing, recapitalizing, or restructuring all or a portion of our existing debt. As discussed in Part II, Item 1A – Risk Factors, we cannot assure you that any of the measures would be successful or sufficient.

 

Sources of Capital

 

Cash flows from operations. Our produced volumes have increased significantly over the past three years as a result of the successful development of our operated properties. However, due to the current depressed oil and natural gas pricing environment, we have temporarily deferred our drilling program, other than four wells that we anticipate drilling in the second fiscal quarter, and we plan to delay the completion of certain wells subject to a number of factors, including the

32


 

price of oil and natural gas, development costs, and the availability of third party work for RockPile. Consequently, our production volume is expected to decrease in fiscal year 2017 as compared to fiscal year 2016, and the cash flows we receive from our production will likely be less than we received in prior years due to lower realized prices.

 

Cash flows from our oilfield services segment decreased significantly in fiscal year 2016 primarily due to efforts to remain competitive in the current oil and natural gas pricing environment by significantly reducing fees that RockPile charges to its customers. As a result of the margin compression on fees charged for services, as well as the likelihood for lower utilization of RockPile services by customers slowing the pace of their development operations, we anticipate that RockPile’s cash flows from operations in fiscal year 2017 may be substantially lower than in fiscal year 2016.

 

Credit facilities. As of April 30, 2016, our maximum credit available under the TUSA credit facility was $1.0 billion, subject to a borrowing base of $225.0 million, which had been redetermined down from $350.0 million on April 28, 2016. Therefore, as of April 30, 2016, we had no borrowing capacity available under the TUSA credit facility, and we had a borrowing base deficiency of $125.0 million, which we elected to pay down in three equal monthly installments. The borrowing base under the TUSA credit facility is subject to redetermination on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. We do not anticipate any further change to our $225.0 million borrowing base prior to the November redetermination.

 

On April 13, 2016, RockPile entered into the RockPile Waiver Amendment, which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 and as of April 30, 2016. The waivers are conditioned on RockPile agreeing to certain informational and process requirements and deadlines. Following the execution of the RockPile Waiver Amendment, RockPile is precluded from drawing additional funds absent further amendment of the facility.

 

Absent a rapid, substantial and sustained increase in commodity prices or favorable negotiations with our credit facility lenders, we do not anticipate that we will have borrowing capacity available under our existing credit facilities to finance any difference between our cash on hand and cash flows from operations and our anticipated capital expenditures.

 

Securities Offerings. Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of public and private offerings of our equity and debt securities. We may from time to time offer debt securities, common stock, preferred stock, warrants and other securities, or any combination of such securities, in amounts, at prices and on terms announced when and if the securities are offered. The specifics of any future public offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus or a prospectus supplement at the time of such offering.

 

Asset Sales. In the past, our acquisition activities have significantly outpaced our asset sales, which have been generally limited to small, opportunistic divestitures or exchanges of leasehold interests. In the current depressed commodity pricing environment, we are strategically reviewing our assets to consider monetizing those that may garner attractive prices or are peripheral to our core businesses. Such assets include, but are not limited to, non-operated acreage, equity investments, equipment, and other real property interests. If commodity prices remain depressed and we are unable to fund our operations or service our debt obligations from other sources of capital, we may be forced to sell portions of our operated core acreage or other assets at distressed prices.

 

Liquidity

 

TUSA Liquidity and Covenants.  On April 28, 2016, TUSA’s credit facility lenders significantly reduced the borrowing base under the credit facility from $350.0 million to $225.0 million, which was a greater reduction than we had anticipated. As of April 30, 2016, TUSA had $347.5 million of outstanding borrowings and $2.5 million of outstanding letters of credit under the credit facility, or $125.0 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). TUSA had cash on hand of approximately $152.3 million at April 30, 2016. TUSA elected to repay the borrowing base deficiency in three equal monthly installments of $41.7 million, the first payment of which was paid on May 31, 2016. Any non-payment of the borrowing base deficiency could result in an event of default.

 

As of April 30, 2016, TUSA was in breach of the credit facility’s minimum current ratio requirement. On May 27, 2016, TUSA entered into the TUSA Forbearance Amendment with its credit facility lenders, pursuant to which the lenders agreed to forbear exercising any rights or remedies available to them arising from any breach related to the minimum

33


 

required current ratio or the senior secured leverage ratio that may have occurred as of April 30, 2016. The forbearance is effective until the earlier of July 8, 2016 or specified forbearance termination events including the commencement of any bankruptcy or reorganization proceeding under applicable bankruptcy or insolvency law.

 

Although it is difficult to forecast future operations in this low commodity price environment, TUSA may not comply with all of the financial covenants contained in its credit facility in future periods unless those requirements are waived or amended or unless TUSA can obtain new capital or equity cure financing. The greater than expected reduction in the borrowing base contributed to the breach of the minimum current ratio requirement at April 30, 2016, and will have a negative impact on TUSA’s expected financial covenant performance for the remainder of fiscal year 2017 and increase the amount of any needed equity cure. TUSA remains in discussions regarding strategic alternatives, but there are no guarantees these discussions or negotiations will be successful. If TUSA is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, TUSA’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable after the forbearance period ends. If this happens, the Company does not currently have sufficient liquidity to make the equity cures for the credit facility that we expect may be necessary in the next 12 months.

 

If the TUSA credit facility lenders declare any financial covenant breach or non-payment of the borrowing base deficiency an event of default, there are cross-default provisions in the Indenture of the TUSA 6.75% Notes (as defined below) that could enable holders of the TUSA 6.75% Notes to also declare some or all of the amounts outstanding under the TUSA 6.75% Notes to be immediately due and payable after the forbearance period ends. TUSA does not have sufficient liquidity to repay the credit facility and the TUSA 6.75% Notes. Therefore, the condensed consolidated balance sheet reflects all of the amounts outstanding under the TUSA credit facility and the balance outstanding of the TUSA 6.75% Notes as current liabilities as of April 30, 2016. TUSA could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of TUSA. Triangle has not guaranteed TUSA’s obligations under the TUSA credit facility or the TUSA 6.75% Notes.

 

RockPile Liquidity and Covenants. On April 13, 2016, RockPile entered into the RockPile Waiver Amendment, which waived any default or event of default in connection with the financial covenants that occurred as of January 31, 2016 and April 30, 2016. We are encouraged that the credit facility lenders have continued to work with us and granted an extension of time to further amend or refinance the credit facility. However, if commodity prices remain depressed and RockPile does not realize an increased market demand or better pricing terms for its services, RockPile does not expect to comply with all of the financial covenants contained in its credit facility throughout fiscal year 2017 unless those requirements are also waived or amended or unless RockPile can obtain new capital or cure financing. RockPile remains in discussions regarding strategic alternatives, but there are no guarantees these discussions or negotiations will be successful. If RockPile is unable to reach agreement with its lenders, obtain waivers, find acceptable alternative financing or obtain equity cure contributions, RockPile’s credit facility lenders could elect to declare some or all of the amounts outstanding under the facility to be immediately due and payable. If this happens, the Company does not currently have sufficient liquidity to make the RockPile equity cure and RockPile does not have sufficient cash on hand to repay this outstanding debt. Therefore, the condensed consolidated balance sheet reflects all of the amounts outstanding under the RockPile credit facility as current liabilities as of January 31, 2016 and April 30, 2016. RockPile could then be required to pursue in- and out-of-court restructuring transactions and Triangle could lose control of RockPile.

 

Triangle Liquidity. Triangle recently engaged certain professional advisors to assist it in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including: (i) obtaining waivers or amendments from RockPile’s and TUSA’s lenders; (ii) obtaining additional sources of capital from asset sales, issuances of debt or equity securities, debt for equity swaps, or any combination thereof; and (iii) pursuing in- and out-of-court restructuring transactions. In connection with a debt restructuring or refinancing, we may seek to convert a significant portion of our outstanding debt to equity, including the exchange of debt for shares of our common stock. In addition, we may seek to reduce our cash interest cost and extend debt maturity dates by negotiating the exchange of outstanding debt for new debt with modified terms or other measures. While we anticipate engaging in active dialogue with our creditors, at this time we are unable to predict the outcome of such discussions, the outcome of any strategic transactions that we may pursue or whether any such efforts will be successful.

 

As a result of the above, substantial doubt exists regarding the ability of Triangle to continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business.

 

34


 

Commodity Derivative Instruments

 

We may utilize various derivative instruments, including costless collars and swaps, in connection with anticipated crude oil sales to reduce the impact of product price fluctuations. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than they would be if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

 

Working Capital

 

As part of our cash management strategy, we periodically use available funds to reduce amounts borrowed under our credit facilities. However, due to certain restrictive covenants contained in our credit facilities regarding our ability to dividend or otherwise transfer funds from the borrower to Triangle, we seek to maintain sufficient liquidity at Triangle to manage foreseeable and unforeseeable consolidated cash requirements. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. We had a working capital deficiency of $662.5 million as of April 30, 2016, compared to $25.7 million of working capital at January 31, 2016.

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

35


 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

 

Commodity Price Risk. Our primary market risk is related to changes in oil prices. The market price of oil has been highly volatile and is likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. We primarily utilize swaps and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

 

We may use costless collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled on a monthly basis. When the settlement price (the market price for oil or natural gas during the settlement period) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us.

 

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TUSA is currently a party to derivative contracts with six counterparties. The Company has a netting arrangement with each counterparty that provides for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparty. The derivative contracts may be terminated by a non-defaulting party in the event of a default by one of the parties to the agreement.

 

The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil prices and to manage its exposure to commodity price risk. While the use of these derivative instruments reduces the downside risk of adverse price movements, these instruments may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional forecasted production, restructure or reduce existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions.

 

The Company’s commodity derivative contracts as of April 30, 2016 are summarized below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted

 

Weighted

 

Weighted

 

 

Contract

 

 

 

Quantity

 

Average

 

Average

 

Average

 

    

Type

    

Basis (1)

    

(Bbl/d)

 

Put Strike

 

Call Strike

  

Price

May 1, 2016 to January 31, 2017

 

Swap

 

NYMEX

 

2,558

 

 

n/a

 

 

n/a

 

$

55.64

February 1, 2017 to January 31, 2018

 

Swap

 

NYMEX

 

2,745

 

 

n/a

 

 

n/a

 

$

53.36

(1)

“NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

 

We have elected not to apply cash flow hedge accounting to any of our derivative transactions and we therefore recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

 

All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the condensed consolidated statements of operations. As of April 30, 2016, the fair value of our commodity derivatives was a net asset of $9.6 million. An assumed increase of 10% in the forward commodity prices used in the April 30, 2016 valuation of our derivative instruments would result in a net derivative asset of approximately $1.3 million at April 30, 2016. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $17.9 million at April 30, 2016.

 

Interest Rate Risk. At April 30, 2016, TUSA and RockPile had borrowed the maximum amounts available under their credit facilities. The TUSA and RockPile credit facility balances at April 30, 2016 were $347.5 million and $112.0 million, respectively. These credit facilities bear interest at variable rates. A 1.0% increase in interest rates would result in additional annualized interest expense of $4.6 million.

 

The TUSA 6.75% Notes and the Convertible Note bear interest at fixed rates.

 

36


 

ITEM 4. CONTROLS AND PROCEDURES.

 

Disclosure Controls and Procedures

 

Our management, with the participation of Jonathan Samuels, our President and Chief Executive Officer, and Douglas Griggs, our Chief Accounting Officer (principal financial officer), evaluated the effectiveness of our disclosure controls and procedures as of April 30, 2016. Based on the evaluation, those officers believe that:

 

·

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and

 

·

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Accounting Officer (principal financial officer), as appropriate to allow timely decisions regarding required disclosure.

 

Changes in Internal Control over Financial Reporting

 

There has not been any change in our internal control over financial reporting that occurred during the quarterly period ended April 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

37


 

PART II.  OTHER INFORMATION

 

Item 1.  Legal Proceedings.

 

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on our business, financial condition or operating results.

 

Item 1A.  Risk Factors.

 

Other than the following risk factors, there have been no material changes to the risk factors set forth in our Fiscal 2016 Form 10-K. Those risks, in addition to the other information set forth in this Quarterly Report on Form 10-Q and in our other filings with the SEC, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

 

TUSA’s lenders periodically redetermine the amount TUSA may borrow under its credit facility, which may materially impact our operations.

   

TUSA uses borrowings under its credit facility to fund its exploration, development, and acquisition activities and for other corporate purposes. At January 31, 2016, TUSA’s borrowing base under its credit facility was $350.0 million. As of April 28, 2016, TUSA had $347.5 million of outstanding borrowings and $2.5 million of outstanding letters of credit under its credit facility. On April 28, 2016, TUSA received notice from Wells Fargo Bank, National Association, as administrative agent and issuing lender under its credit facility, that its borrowing base had been redetermined in accordance with the credit facility and reduced to $225.0 million effective immediately. As of April 28, 2016, TUSA had $125.0 million outstanding under its credit facility in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). The credit facility provides that within 10 days after TUSA’s receipt of a notification of a borrowing base deficiency, TUSA must elect to cure the borrowing base deficiency through any combination of the following actions: (A) repay amounts outstanding under the credit facility sufficient to cure the borrowing base deficiency within 30 days after receipt of the borrowing base deficiency notice; (B) pledge as collateral additional oil and gas properties acceptable to the administrative agent and lenders within 30 days after receipt of the borrowing base deficiency notice; (C) arrange to pay the deficiency in three equal monthly installments beginning 30 days after receipt of the deficiency notice; or (D) cure the borrowing base deficiency using a combination of options (A)-(C). As of April 28, 2016, TUSA had cash on hand of approximately $152.3 million. TUSA elected to repay the borrowing base deficiency in three equal monthly installments, the first payment of which was due by May 31, 2016 (a payment due on a weekend or holiday shall be made on the next business day). TUSA made the first installment payment on May 31, 2016.

 

The borrowing base under TUSA’s credit facility is redetermined semi-annually on or about May 1 and November 1 based upon a number of factors, including changes in proved reserves and TUSA’s overall financial condition. The administrative agent and the lenders may also request unscheduled borrowing base redeterminations twice during each calendar year upon ten days’ notice to the other party. There is no guarantee that the administrative agent and the lenders will not further reduce our borrowing base, either at the next regularly scheduled redetermination in fall 2016 or at their election pursuant to their right to implement two unscheduled redeterminations each year. If the borrowing base is further reduced (and our borrowing base deficiency increases) following a regularly scheduled, semi-annual redetermination, TUSA will be required to elect to cure the borrowing base deficiency through any combination of the actions described in (A) through (D) above. In contrast, if a borrowing base deficiency results from an unscheduled redetermination, TUSA must immediately repay the excess and may not remedy such deficiency by pledging additional collateral or repaying the excess in installments. Because TUSA’s credit agreement is effectively fully drawn, any further reduction of the borrowing base would result in a borrowing base deficiency that TUSA would be required to remedy. A reduction in TUSA’s borrowing base, or an acceleration of the deficiency repayment schedule, would materially and adversely impact our liquidity, which would materially limit our exploration, development, and acquisition activities and adversely affect our operations and financial results.

 

38


 

We are evaluating a variety of strategic alternatives to improve our balance sheet, but there is no guarantee that any such alternatives can be effectuated on acceptable terms or at all.

 

We are evaluating a number of measures to enhance our liquidity and improve our balance sheet. On March 24, 2016, we announced our retention of financial and legal advisors to assist us in evaluating our strategic alternatives. On May 12, 2016, RockPile also announced that it has retained financial and legal advisors to assist it in its ongoing strategic review process. The strategies we are evaluating include modifying our operations; selling material assets or business segments; seeking additional financing; or refinancing, recapitalizing, or restructuring all or a portion of our existing debt. We have engaged in discussions with certain of our stakeholders with respect to a potential consensual restructuring or recapitalization of the Company and/or certain of its subsidiaries, and to date, such discussions have not resulted in any definitive agreements relating thereto.

 

These alternative measures may not be available on commercially reasonable terms or at all, may not be successful, and may not permit us to meet our scheduled debt service and other obligations. To the extent inadequate cash flows from operations and other available capital resources require us to dispose of material assets or operations to meet our debt service and other obligations, we may not be able to consummate these dispositions for fair market value, in a timely manner, or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. To the extent inadequate liquidity or other considerations require us to seek to restructure or refinance our debt, our ability to do so will depend on numerous factors, including many beyond our control, such as the condition of the capital markets and our financial condition at such time. Any refinancing or restructuring of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations.

 

Moreover, we cannot guarantee that any particular refinancing or restructuring alternatives, such as refinancing our existing indebtedness, extending the maturity dates of such indebtedness, or otherwise amending the terms thereof, would be sufficient or could be effectuated at all. If we are unable to service our debt and other obligations through cash flows from operations and are unable to effectuate one or more of the alternative measures and transactions we currently are evaluating, we may be required to reorganize the Company in its entirety and therefore cannot assure you that the Company will continue in its current state or that your investment in the Company will retain any value. The recent severe redetermination of the borrowing base under the TUSA credit facility substantially increases this risk.

 

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

 

The following table summarizes our purchases of shares of our common stock during the fiscal quarter ended April 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Maximum number

 

 

 

 

 

 

 

 

Total number of

 

of shares that may

 

 

 

Total Number

 

Average

 

shares purchased

 

yet be purchased

 

 

    

of Shares

    

Price Paid

    

as part of publicly

    

under the plans

 

 

 

Purchased

 

Per Share

 

announced plans (2)

 

at month end

 

February 1, 2016 to February 29, 2016

 

2,976

 

$

0.39

 

 —

 

5,811,091

(3)  

March 1, 2016 to March 31, 2016

 

200,543

 

 

0.88

 

 —

 

6,033,290

(4)  

April 1, 2016 to April 30, 2016

 

11,890

 

 

0.52

 

 —

 

6,033,290

 

 

 

215,409

(1)  

$

0.86

 

 —

 

 

 


(1)

Shares of common stock surrendered by certain employees to the Company in satisfaction of their tax liability upon the vesting of their restricted stock units. The number of shares of common stock actually issued to such employees upon the vesting of their restricted stock units was net of the shares surrendered in satisfaction of their tax liability. The withheld shares are not issued or considered common stock repurchased under the repurchase program described below.

 

39


 

(2)

As reported in Current Reports on Form 8-K filed with the SEC on September 11, 2014 and October 17, 2014, the Company’s Board of Directors approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares of common stock potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). Shares of common stock repurchased under the program may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program may be executed using open market purchases pursuant to Rule 10b-18 under the Exchange Act, pursuant to a Rule 10b5-1 plan, in privately negotiated agreements, or other transactions. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. As of April 30, 2016, an aggregate of 11,431,744 shares of the Company’s common stock have been repurchased under the program.

 

(3)

Includes the number of shares of common stock remaining available for repurchase pursuant to Tranche 2, plus the number of shares of common stock available for repurchase pursuant to Tranche 3 based on the paid-in-kind interest accrued on the Convertible Note as of December 31, 2015. All shares of common stock authorized for repurchase under Tranche 1 have been exhausted.

 

(4)

Includes an additional 222,198 shares of common stock potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the Convertible Note on March 31, 2016.

 

Item 3.  Defaults Upon Senior Securities.

 

None.

 

Item 4.  Mine Safety Disclosures.

 

Not Applicable.

 

Item 5.  Other Information.

 

Not Applicable.

 

40


 

ITEM 6.  EXHIBITS.

 

 

 

 

 

 

 

Exhibit No.

 

Description

 

 

 

3.1

 

Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.

 

 

 

3.2

 

Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.

 

 

 

3.3

 

Amended and Restated Bylaws of Triangle Petroleum Corporation, effective December 2, 2015, filed as Exhibit 3.3 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on December 8, 2015 and incorporated herein by reference.

 

 

 

10.1

 

Form of Director and Officer Indemnification Agreement, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 24, 2016 and incorporated herein by reference.

 

 

 

10.2*

 

Waiver and Amendment No. 2 to Credit Agreement, dated April 12, 2016, between RockPile Energy Services, LLC, as Borrower, Citibank, N.A., as Administrative Agent and Collateral Agent, and the banks and other financial institutions signatories thereto.

 

 

 

31.1*

 

Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

31.2*

 

Certification of Chief Accounting Officer (principal financial officer) pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.1*

 

Certifications of Chief Executive Officer and Chief Accounting Officer (principal financial officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS*

 

XBRL Instance Document

 

 

 

101.SCH*

 

XBRL Taxonomy Extension Schema Document

 

 

 

101.CAL*

 

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

 

101.LAB*

 

XBRL Taxonomy Extension Label Linkbase Document

 

 

 

101.PRE*

 

XBRL Taxonomy Extension Presentation Linkbase Document

 

 

 

101.DEF*

 

XBRL Taxonomy Extension Definition Linkbase Document

 


* Filed herewith.

 

 

 

 

41


 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

TRIANGLE PETROLEUM CORPORATION

 

 

 

Date:  June 7, 2016

 

By: 

 

/s/ JONATHAN SAMUELS

 

Jonathan Samuels

 

President and Chief Executive Officer

 

 

USTIN, 2015

 

 

 

Date:  June 7, 2016

 

By: 

 

/s/ DOUGLAS GRIGGS

 

Douglas Griggs

 

Chief Accounting Officer (principal financial officer)

 

 

 

 

 

 

42